• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
  • 同族专利
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    • 专利摘要:
    The present invention relates to a wavelet estimation that can be performed in a reservoir simulation model that is constrained by seismic inversion data and drill reports. A synthetic seismic trace is generated with an estimated wavelet. The reservoir simulation model is revised based on results from model comparisons to actual data or basic seismic data and is then used to perform wavelet estimation. The estimated wavelet can then be used to plan additional production at the wellsite environment, additional production at additional wellsite environments, or any other production and drilling operation for the well site. any given present or future wellsite environment.
    公开号:FR3060174A1
    申请号:FR1760856
    申请日:2017-11-17
    公开日:2018-06-15
    发明作者:Travis St. George Ramsay；Felix Rafael Segovia
    申请人:Landmark Graphics Corp；
    IPC主号:
    专利说明:

    TECHNICAL AREA
    The embodiments of the present invention relate, in general, to seismic measurements for subsurface formations and, more particularly, the estimation of wavelets for a four-dimensional characterization of subsurface properties on the basis of a simulation. dynamic.
    BACKGROUND OF THE INVENTION
    When exploring for hydrocarbons, seismic energy can be generated and transmitted in a formation positioned in an area of interest. Seismic waves can be reflected or refracted outside the formations and recorded by acoustic receivers positioned in or near a wellbore at surface level or under the sea. Seismic waves reflected by the formations can be sampled under the form of seismic data and used to estimate the properties or characteristics of the formations in the area of interest. A seismic inversion involving a wavelet estimation can be used to transform the seismic data into one or more formation properties which quantitatively describe the subsurface.
    BRIEF DESCRIPTION OF THE FIGURES
    Figure 1 is a schematic cross-sectional diagram showing an example of a wellbore environment for acquiring seismic data and drilling report data for analyzing subsurface properties over time, in one or more aspects of this disclosure;
    FIG. 2 is a schematic diagram in cross section representing an example of a marine environment for acquiring seismic data for the purpose of estimating wavelets for a four-dimensional characterization of subsurface properties on the basis of a dynamic simulation, according to a or more than one aspect of this disclosure;
    Figure 3 is a diagram illustrating an example of an information handling system, according to one or more aspects of this disclosure;
    2016-IPM-099958-L1-EN 2 Figure 4 is a diagram illustrating a system for creating basic seismic data, according to one or more aspects of this disclosure; and FIG. 5A and FIG. 5B represent a process diagram illustrating the estimation of wavelets for a derived seismic, according to one or more aspects of the present invention.
    Although embodiments of the present disclosure have been presented and described and are defined by reference to examples of embodiments of the disclosure, these references do not limit the disclosure and no limitation should be inferred. The object disclosed admits considerable modifications, transformations and equivalents of form and function, as will be understood by a specialist in the field and who benefits from this disclosure. The embodiments presented and described of this disclosure are only examples, and are not exhaustive of the scope of the disclosure.
    DETAILED DESCRIPTION
    For the purposes of this disclosure, computer-readable media includes any instrumentality or aggregation of instrumentalities that may retain data and / or instructions for a period of time. Computer readable media may include, for example, but not limited to, storage media such as a direct access storage device (for example, a hard disk drive or a floppy drive), a device sequential access storage (eg, tape drive), compact disc, CD-ROM, DVD, RAM, ROM, erasable and electrically programmable read-only memory (EEPROM) and / or flash memory; as well as communication media such as wires, optical fibers, microwaves, radio waves, and other electromagnetic and / or optical carriers; and / or any combination of the above. In the context of this disclosure, an information manipulation system can include any instrumentality or any aggregate of instrumentalities making it possible to calculate, classify, process, transmit, receive, retrieve, to produce, switch, store, display, manifest, detect, record, reproduce, manipulate or use any form of information, intelligence or data for any purpose commercial, scientific, control, or other. For example, an information manipulation system can be a personal computer, a network storage device, or any other suitable device, and
    2016-IPM-099958-U1-EN 3 may vary in size, shape, performance, functionality and price. The information handling system may include a random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or a hardware or software control logic, a ROM, and / or other types of non-volatile memory. Additional components of the information manipulation system may include one or more disk drives, one or more network ports for communicating with external devices, as well as various input and output (I / O) devices, such as keyboard, mouse and video display. The information handling system may also include one or more buses for transmitting communications between the various hardware components.
    Illustrative embodiments of the present invention are described in detail in this document. For the sake of clarity, all the characteristics of an actual implementation may not be described in the present specification. It will of course be understood that in the development of one of these real embodiments, many specific decisions related to the implementation can be taken to achieve the specific objectives of the implementation, which may vary from one implementation work to another. In addition, it will be understood that such a development effort may be complex and time consuming, but that it would nevertheless become a routine task for an ordinary specialist in the field who benefits from the present disclosure.
    In order to better understand the present invention, the following examples of certain embodiments are given. It should not be interpreted in any way as the following examples limit or define the scope of the invention. The embodiments of this disclosure can be applied to horizontal, vertical, deviated or otherwise non-linear wells in any type of underground formation. The embodiments can be applied to injection wells, as well as to production wells, in particular hydrocarbon wells.
    One or more embodiments relate to the estimation of wavelets for repetitive seismic prospecting data for the required purpose of carrying out a seismic inversion in control prospecting using pseudo-drilling reports derived from petro- elastic (PEM) in order to generate a more precise mapping or analysis of one or more formation properties. Such an estimate
    2016-IPM-099958-U1-EN 4 of wavelets to execute a seismic inversion workflow can be achieved by one or more estimation methods such as, but not limited to, methods that only call upon seismic data or methods using combined seismic data and drilling reports. A wavelet can be estimated using phase and amplitude spectra using a drilling report and seismic data to produce a synthetic seismic trace based on the basic or initial seismic data to obtain a precise mapping or analysis. one or more formation properties over a bidirectional time interval.
    Although a wavelet estimation in a basic seismic survey can be performed using only seismic methods, a subsequent phase rotation to obtain the wavelet can give a result that does not accurately reflect the underground or subsurface formation time elapsed when a constant phase is assumed. For example, a repetitive seismic acquisition can be used to analyze changes in a reservoir or a formation of interest, for example, underground formations. Although changes in the vicinity of the wellbore may occur, production reports are generally not previously acquired after the start of production, which requires different processes to estimate Tondelette in a control survey that takes into account with precision of phase and amplitude spectra for precise dynamic characterization of a reservoir. Another wavelet estimation technique uses a modeling-based technique incorporating an adaptive evolution strategy with a covariance matrix and applies reduction of Gaussian data space to iteratively eliminate nonconforming models. However, such methods assume that the production flows take place in a superimposed fashion and that an inversion is carried out on a block model. In yet other methods, changes in the location of a well are assumed by a substitution of fluid which is governed by a model of rock physics. However, with this process, the fluid dynamics associated with hydrocarbon production cannot be taken into account but, rather, estimated changes in pressure response and fluid saturation can be used to direct the reversal of the flow. control prospecting, which can increase uncertainty. In one or more aspects of this disclosure, a wavelet estimation can be performed in a reservoir simulation model constrained by seismic data and using drilling reports or drilling report data because the temporal relationship between the
    2016-IPM-099958-U1-EN 5 seismic control and the calibrated reservoir simulation model is more consistent and can provide a more precise description of the formation or subsurface.
    Various aspects of this disclosure may be implemented in various environments. Figure 1 is a schematic cross-sectional diagram showing an example of a wellbore environment for acquiring seismic data and drilling report data for wavelet estimation for four-dimensional characterization of subsurface properties on the basis of a dynamic simulation, according to one or more aspects of this disclosure. An example of a wellbore environment 100 for acquiring seismic data and drilling reports in accordance with one or more aspects of this disclosure is illustrated. The wellbore environment 100 includes a derrick 102 positioned at a surface 104. The derrick 102 can support components of the wellbore environment 100, including a drill bit 110 coupled to a drill string 106 which extends below the surface 104 in a borehole 108.
    The drill string 106 may include one or more downhole tools, for example, a downhole assembly 114, positioned on the drill string 106 above the drill bit 110. The downhole assembly 114 includes a combination of various components, such as one or more drill bits 116, a downhole data collection tool 118, and a downhole motor assembly 120 for housing a motor for the drill bit 110. In in some aspects, downhole data collection may include a network of seismic sensors 122, such as geophones, or the seismic sensors 122 may come into contact with a wall of the wellbore 108. The seismic sensors 122 may be placed in operation in response to seismic waves 124 generated by a seismic source 126 positioned on the surface 104 near the wellbore 108. The seismic source 126 can generate seismic energy in order to form d seismic waves 124 which can be transmitted from surface 104 through formation 112 near wellbore 108. The seismic source 126 may include, but is not limited to, any of an air cannon , a plasma sound source, a falling weight truck, one or more explosive devices, an electromagnetic pulse (EMP) energy source, and a seismic vibrator. One or more seismic waves 124 generated by the seismic source 126 can be reflected or refracted by the formation 112 and sampled by the seismic sensors 122 positioned on the seismic tool 118.
    2016-IPM-099958-U1-FR 6
    The one or more samples or information received by the seismic sensors 122 of the seismic tool 118 can be recorded and used by a data acquisition unit 128 at the surface 104 in order to acquire seismic data to provide information or data relating to one or more properties or characteristics of the formation 112. In one or more embodiments, the seismic sensors 122 can be designed to sample the seismic waves 124 reflected or refracted from the formation 112 at time intervals predetermined. In one or more embodiments, the seismic source 126 may be designed to generate and transmit the seismic waves 124 at predetermined time intervals. In one or more embodiments, the seismic data 104 can be generated by the seismic sensors 122 and stored in the data acquisition unit 128 once a week, per month, per quarter, per year or any other other time interval. In one or more embodiments, the seismic tool 118 can record prospecting data for vertical seismic profiling and drilling report data. In one or more embodiments, any surface seismic data recorded by any of the seismic tools 118 may occur before the erection of a derrick 102 or before any drilling in the well environment drilling 100.
    Several methods exist for collecting drilling report data as downhole information, including logging during drilling ("LWD") and measurement during drilling ("MWD"). In LWD, data is generally collected during the drilling process, which does not require removing the drilling module to insert a wired logging tool. Therefore, the LWD allows the driller to make precise changes or corrections in real time to optimize performance while minimizing downtime. MWD is the term for measuring downhole conditions regarding the movement and location of the drilling module while drilling continues. The LWD focuses more on the measurement of training parameters. Although distinctions between MWD and LWD may exist, the terms MWD and LWD are often used interchangeably.
    In one or more embodiments, one or more samples received by the seismic sensors 122 can be stored in a storage device or a memory located at the bottom of the well, for example, in a downhole assembly 114. The one or several samples can be recovered for analysis by a data acquisition unit
    2016-IPM-099958-U1-EN 7 data 128 at the bottom of the well or, for example, after the recovery of a downhole assembly 114. In one or more embodiments, the seismic tool 118 can be coupled in communication with the data acquisition unit 128 by any suitable device or mechanism such as, but not limited to, a wired, wireless, fiber optic, telemetry device or mechanism, what other communication device or mechanism or any combination thereof. Although only one data acquisition unit 128 is shown, the wellbore environment 100 may include any number of devices or tools for acquiring information or data from the seismic tool 118, as one or more information manipulation systems. In one or more embodiments, any of the devices or components positioned on the surface 104 as illustrated (for example, the seismic source 126 and the data acquisition unit 128) and any of its devices positioned at the bottom of the well in the wellbore 108 as illustrated (for example, in the seismic tool 118) can be positioned on the surface 104, in the wellbore 108 or in any combination of positioning on the surface 104 or in borehole 108.
    Figure 2 is a schematic cross-sectional diagram showing an example of a marine environment for acquiring seismic data in order to analyze the reflective properties of a round-trip subsurface according to one or more aspects of this disclosure. A seismic acquisition environment 200 may include a seismic vessel 220. The seismic vessel 220 may tow one or more seismic sources 204, such as a pulse source or a vibration source. The seismic sources 204 can emit seismic waves 206 through the ocean floor 208. The seismic waves 206 can be reflected or refracted outside of the underground formations 210 under the ocean floor 208 and received by a network of seismic sensors 212, such as hydrophones, located behind the seismic ship 220 on one or more streamers 214. In certain aspects, the streamers 214 may include electrical or optical fiber cabling to connect the network of sensors 212 to the equipment located on the ship 100, in particular a data acquisition unit 216. The sensors 212 can measure the reflections of the seismic waves 124 and transmit the measurements via the sea streamers 214 for storage purposes in the data acquisition unit 216. The data acquisition unit 216 may be similar to data acquisition unit 128 and may include render one or more information manipulation systems.
    2016-IPM-099958-U1-FR 8
    Figure 3 is a diagram illustrating an example of an information handling system, according to one or more aspects of this disclosure. The data acquisition unit 216 or the data acquisition unit 128 can take a form similar to that of the information handling system 300. A processor or a central processing unit (CPU) 301 of the data processing system information manipulation 300 is coupled in communication with a memory control center or memory controller 302. The processor 301 can comprise, for example, a microprocessor, a microcontroller, a digital signal processor (DSP), an integrated circuit specific application (ASIC), or any other digital or analog circuit configured to interpret and / or execute the instructions of a program and / or process data. Processor 301 can be configured to interpret and / or execute instructions from a program or other data retrieved and stored in any memory, such as memory 303 or hard drive 307. Hard drive 307 can include , but not limited to, a hard disk drive, an optical drive or any other non-transient storage medium or computer readable medium as mentioned above. Program instructions or other data may constitute parts of software or an application to implement one or more methods or embodiments described in this document. The memory 303 can include a read only memory (ROM), a random access memory (RAM), a solid state memory, or a memory based on a disc. Each memory module can include any system, device or apparatus configured to retain program instructions and / or data for a period of time (for example, computer readable non-transient media). For example, instructions from software or an application can be retrieved and stored in memory 303 for execution by processor 301.
    Modifications, additions or omissions can be made to Figure 3 without departing from the scope of this disclosure. For example, Figure 3 shows a particular configuration of components of the information handling system 300. However, any suitable configuration of components can be used. For example, the components of the information manipulation system 300 can be implemented by physical or logical components. In addition, in certain embodiments, the functionality associated with the components of the information handling system 300 can be implemented in specialized circuits or components. In other embodiments, the functionality associated with the components of the
    2016-IPM-099958-U1-EN 9 information manipulation 300 can be implemented in a configurable circuit or universal components. For example, the components of the information manipulation system 300 can be implemented by configured computer program instructions.
    The memory control center (MCH) 302 may include a memory controller for directing information to or from various system memory components within the information manipulation system 300, such as memory 303, the memory element storage 306 and the hard drive 307. The memory control center 302 can be coupled to the memory 303 and to a graphics processing unit (GPU) 304. The memory control center 302 can also be coupled to a control center input / output (ICH) or input and output controller 305. The input and output control center 305 is coupled to storage elements of the information handling system 300, in particular a storage element 306, which may include a flash ROM which includes a basic computer input / output system (BIOS). The input and output control center 305 is also coupled to the hard drive 307 of the information manipulation system 300. The input and output control center 305 can also be coupled to an I / O super chip 308 , which is itself coupled to several I / O ports of the computer system, in particular the keyboard 309 and the mouse 310.
    Figure 4 is a diagram illustrating a system for creating basic seismic data, according to one or more aspects of the present disclosure. A system 400 for acquiring samples of information or seismic data 404 comprises a data acquisition unit 128. The data acquisition unit 128 is coupled to the seismic tool 118 which may include one or more seismic sensors 122 for detecting seismic waves generated by a seismic source 126 as illustrated and discussed above with respect to Figure 1. Although reference is made to Figure 1, the present disclosure contemplates the use of any one components of Figure 2 or any other data acquisition unit, seismic tool, seismic sensor, different seismic equipment, or any combination thereof.
    The data acquisition unit 128 can receive the information sample or samples from one or more sensors 122 of the seismic tool 118 and store the information sample in a storage device 402. The
    2016-IPM-099958-U1-EN 10 storage device 402 may include, but is not limited to, database, RAM, hard disk drive, optical drive or any other storage medium not transient. The storage device 402 can store the information sample generated from the seismic tool 118 in the form of seismic data 404. In one or more embodiments, the seismic data 404 can comprise raw information coming from one or more sensors 122 of the seismic tool 118. In one or more embodiments, the seismic tool 118 or an intermediate device between the seismic tool 118 and the data acquisition unit 128 may include a processor or an information manipulation system (such as an information manipulation system 300) for processing any part of the information sample before transmitting the information sample to the acquisition unit 128 for data storage in the form of seismic data 404.
    The system 400 can also include an information manipulation system 300 which is coupled in communication with the data acquisition unit 128. In one or more embodiments, the information manipulation system 300 can be positioned at a location remote from a wellbore environment (for example, wellbore environments 100, 200 in Figures 1 and 2 respectively). In one or more embodiments, the seismic data 404 can be transmitted from the data acquisition unit 128 and stored in a memory device 418 of the information manipulation system 300 via a network 408 The data acquisition unit 128 and the information manipulation system 300 can be coupled to, understand or include respective communication devices 410A and 410B. Communication devices 410A, 410B include or are coupled to antennas 412A and 412B, respectively. The antennas 412A and 412B can transmit and receive information via the network 408. Although a network 408 is illustrated, the present disclosure contemplates any type of communication as, but not limited to, the using a wired connection, wireless connection, portable storage devices, or any other type of communication appropriate for a given environment or operation.
    As mentioned above with respect to Figure 3, the information handling system 300 may include several components such as, but not limited to, a processor 301, a bus 416 and a memory device 418. The processor 301 can
    2016-IPM-099958-U1-EN 11 execute one or more instructions or one or more programs or cause one or more operations to be performed to create, collect, generate or store basic seismic data or seismic control data by the using the seismic data 404 received from the data acquisition unit 128. The processor 301 can execute one or more instructions or one or more programs to create the basic seismic data or the seismic control data. The processor 301 can execute one or more instructions 420 stored in the memory device 418 to implement any of the operations, according to one or more aspects of this disclosure. Processor 301 may include one or more processors, one or more modules or components that are configured or capable of executing one or more instructions or one or more software programs, or any other software, hardware, or combination thereof. ci configured or capable of acquiring and processing seismic data 404 according to one or more aspects of this disclosure. Processor 301 can include, but is not limited to, a programmable pre-broadcast integrated circuit (FPGA), a specific application integrated circuit (ASIC), a microprocessor, or any combination thereof. The memory device 418 can include any type of storage device or medium which retains stored information or data when it is not supplied with power, for example a non-transient storage medium. For example, the memory device 418 can include any type of computer-readable medium as mentioned above. In one or more embodiments, at least part of the memory device 418 can store seismic data 404.
    FIG. 5A and FIG. 5B represent a process diagram illustrating the estimation of wavelets for a derived seismic according to one or more aspects of the present invention. A wavelet estimate can be obtained for seismic data to assist in the production and management of a reservoir. In step 500, for a given time instance, basic seismic data of an area of an underground formation is received or acquired and processed, for example the seismic data 404 of FIG. 4. In one or more modes In one embodiment, a sample of information associated with a reservoir or with a formation of interest (for example, the underground formation 210 of FIG. 2) can be acquired by or received from the data acquisition units 216 from the sensors 212 in Figure 2 to a specific instance of time. The information sample can be stored as seismic data (e.g., seismic data 404 in Figure 4) in a storage device (e.g., storage device 402 in Figure 4). After the acquisition by
    2016-IPM-099958-U1-EN 12 the data acquisition unit 128, the seismic data 404 can be communicated or transmitted to a computing device (for example, the information manipulation system 300). The seismic data 404 can be communicated or transmitted using any device, mechanism or protocol, for example as mentioned above with respect to FIG. 4. The seismic data 404 is processed by the information handling system 300 to obtain a description of the subsurface formation (for example, underground formation 112 in Figure 1 and underground formation 210 in Figure 2). In one or more embodiments, the basic seismic data (such as seismic data 404) is collected in the form of raw unordered data. The basic seismic data is processed to maximize the useful bandwidth of the basic seismic data in order to correct the structural representation, as closely as possible, of the subsurface description, for example the reflexivity of the subsurface. For example, basic seismic data is placed in a common pool to generate a single seismic image that represents the subsurface formation. In one or more embodiments, the basic seismic data can be processed using any method or technique such as, but not limited to, static correction, frequency filtering, skew correction, speed analysis, stacking and migration, or any combination of these.
    In step 502, an initial petrophysical and rock physics analysis is performed to determine or generate one or more drilling reports. Petrophysical and rock physics analysis provides an understanding of rock and fluids from the subsurface or underground formation and shows how rock and fluids are associated with basic seismic data. For example, one or more petrophysical properties such as, but not limited to, porosity, thickness, resistivity, sonic, gamma rays, spontaneous potential, density, transit time, identification and characterization of the fluids, or any other property or record associated with the collected drilling report data can be determined or identified using one or more models based, at least in part, on the processed 404 seismic data from the step 500, for a given reservoir, like the underground formations 112 and 210 respectively in FIGS. 1 and 2.
    In step 504, one or more wavelets are estimated based, at least in part, on any of the unique generated seismic image, the analysis
    2016-IPM-099958-U1-EN 13 petrophysics and the analysis of rock physics. One or more synthetic seismic traces are generated based, at least in part, on the estimated one or more wavelets. For example, sonic and density drilling reports can be used to generate or calculate an impedance diagram. Reflection coefficients can be calculated at the abrupt changes in the impedance diagram and used to form a series of reflection coefficients. The series of reflection coefficients can be processed by convolution with an impulse (extracted or estimated) to generate a synthetic seismic trace or a synthetic seismogram which is used to calibrate the drilling report against the actual or basic seismic data. This link between well and seismic may include a synthetic seismogram constructed from a calibrated P impedance diagram which is matched with a seismic trace. A filter is determined which corresponds to the bandwidth of the basic seismic data. The filter is applied to the synthetic seismogram and the result is shifted in time and phase shifted to correspond to the basic seismic data, for example the seismic data 404. This determined filter is an estimated wavelet. The estimated wavelet can be determined using any suitable technique, methodology or modeling.
    In step 506, the one or more synthetic seismic traces generated are compared with the basic seismic data, for example the seismic data 404, to determine whether a wavelet estimated suitable has been generated. If the synthetic seismic trace does not correspond to the basic seismic data according to a predetermined threshold or degree of correlation, the method continues at step 504 to generate one or more wavelets estimated additional on the basis of an adjustment with respect to the wavelet phase, at the link of the well to the seismic, or both. If the synthetic seismic trace corresponds to the basic seismic data according to a predetermined threshold or degree, the process continues at step 508 and it is determined whether the modeled data (like the synthetic seismic trace) are comparable to or to l '' within a predetermined range or threshold of data collected or measured (such as basic seismic data). For example, a synthetic seismogram or a synthetic seismic trace can be compared to basic seismic data, a fundamental measurement can be compared to a drilling report at a predetermined depth, and a geological mapping (distribution of physical properties for the subsurface) be compared to a range of data from one or more drilling reports. Any other comparison or assessment may be made to determine that the modeled data is comparable to the data collected or measured, or that it
    2016-IPM-099958-U1-EN 14 accurately reflect training 112. If they are not comparable, one or more corrections can be made to one or more parameters of the model and the process continues to step 502. The one or several corrections may include one or more diagram corrections due to erosion zones or to the borehole environment, to the analysis of the sensitivity of the wavelet phase, to an update of the supposed matrix in a model of rock physics, to a property average in the drilling report, to a link of the well to the seismic or any combination of these.
    If comparability is determined in step 508, the process continues to step 510 where filtering of drill log data and creation of a subset takes place. For example, one or more spurious data points from the basic seismic data can be eliminated, the data from the one or more drilling reports are moreover normalized or an error correction is applied in order to create a subset of the seismic data one or more drilling reports. In step 512, one or more spatial constraints are determined by an interpretation of the faults of the subset of the basic seismic data, an interpretation of the horizons of the subset of the basic seismic data or both.
    In step 514, a seismic inversion using one or more determined spatial constraints is performed on the basis, at least in part, of the subset of the basic seismic data, for example the seismic data 404. In step 516, a fine-scale geocellular stratigraphic grid is constructed or generated on the basis, at least in part of a stratigraphic frame incorporating at least one of the one or more spatial constraints. In step 518, the seismic inversion is blocked on the fine-scale geocellular stratigraphic grid. In step 520, a lithotype proportion map or model is created based on a diagram and seismic data or calculations from any of the previous steps.
    In step 522, it is determined whether to constrain the petrophysical property model by a deposition facies model based, at least in part, on the map or the lithotype proportion and inversion model. seismic blocked on the fine-scale geocellular stratigraphic grid. For example, the subset of basic seismic data (such as 404 seismic data) can be used to construct a model of deposition facies. If it is determined that the petrophysical property model must be constrained by a
    2016-IPM-099958-L1-EN 15 deposition facies model, the continuous process towards step 524 where the modeling of a facies is carried out. If it is determined that the petrophysical property model should not be constrained, the process continues at step 526. In step 526, modeling of the petrophysical properties is performed.
    In step 528, one or more subsurface flow unit properties (or rock-like properties) and one or more characteristics of the reservoir fluids are collected. In one or more embodiments, one or more flow unit properties (or rock-like properties) can include, but are not limited to, mineralogy, distribution of pore thresholds, distribution of grain, relative permeability, capillary pressure, wettability or any combination thereof. In one or more embodiments, the characteristics of the reservoir fluids may include, but are not limited to, pressure, temperature and volume (PVT), fluid model, one or more other descriptions of subsurface fluids , or any combination thereof.
    In step 530, a flow simulation model is created and a flow simulation is generated. The flow simulation model is used to simulate a multiphase flow through the reservoir to confirm and predict the production of reservoir fluids from this reservoir. The flow simulation model can be based, at least in part, on any model or parameter such as, but not limited to, a petrophysical property model, a description of fluids and rock-fluids, and planning a well. In step 532, it is determined whether the production modeled from the flow simulation model is correlated with a production history for a reservoir or an underground formation of interest (for example, underground formations 112, 210 of Figures 1 and 2, respectively) for a tolerance defined by a user. If the flow simulation model does not correlate according to a tolerance defined by a user with the available production history, the process continues at step 530 where a new flow simulation model is created or updated on the basis of previous modeling efforts based on the petrophysical property model, one or more properties of a wellbore (for example, wellbore 108 in Figure 1), a fluid model, adjustments made to relative permeability, permeability, water-oil contact (WOC), transmissibility and all other parameters known to those skilled in the art. If the flow simulation model has a correlation, a
    2016-IPM-099958-U1-EN 16 flow simulation forecast is produced in step 534. The flow simulation forecast model maps or provides a prediction of hydrocarbon production from the formation of subsurface, for example the subsurface environment 200 in Figure 2. The flow simulation output of the flow simulation forecast model may include one or more three-dimensional arrays of saturation, pressure and petro-elastic properties. The flow simulation output can be analyzed, for example, by a user or other software application, to determine one or more flow properties of hydrocarbon production from wellbore 108. One or more several petro-elastic properties from the flow simulation forecast model can be used to estimate a wavelet for control prospecting.
    In step 536, the seismic control data are acquired. The seismic control data for a reservoir or an underground formation of interest (for example, the underground formations 112 and 210 in Figures 1 and 2, respectively) include seismic data acquired after a period of time. For example, basic or initial seismic data can be acquired and subsequently, for example after the start of hydrocarbon production, seismic control data can be acquired. Seismic control data can be acquired in a similar manner to that described above with respect to seismic data 404 in Figure 4. Seismic control data can be acquired to analyze changes in the reservoir of interest due to this production of hydrocarbons after a period of time has passed. Any time interval may elapse before the acquisition of seismic control data such as, but not limited to, several months, one year, five years, ten years, or any other time interval. The seismic control data can be acquired in the same area or in the same environment as the basic seismic data in order to ensure the continuity of the repetitive signal.
    In step 538, the seismic control data are processed or re-processed in order to obtain a seismic volume. For example, seismic control data can be used in the monitoring of a repetitive seismic tank where a comparison of three-dimensional seismic surveys is carried out at two or more than two time points. The acquired seismic control data are generally raw unordered data. Processing and reprocessing of seismic control data
    2016-IPM-099958-U1-EN 17 maximize the useful bandwidth to provide or present (for example, to provide or present to an operator or specialist in the art) a correct structural image to represent, in a way as close as possible, the reflectivity of the subsurface. For example, seismic data can be placed in a common pool and a single seismic image that represents the subsurface formation can be generated based on the common pool. The processing and the reprocessing can use the same parameter or parameters as those used for the processing of basic seismic data in step 500. In step 540, a petroelastic model (PEM) is produced or generated by a simulator of tank at a predetermined output frequency. For example, the reservoir simulator can be a software application or program that receives inputs that describe a fluid model, rock-fluid interaction, petrophysical descriptions of porous media, descriptions of wellbore (such as trajectories, constraints and planning) and uses numerical modeling techniques to predict the multiphase flow of fluids in a modeled reservoir. The predetermined output frequency is based, at least in part, on a frequency of acquisition of seismic control data. In one or more embodiments, the frequency of acquisition of seismic control data can be two, three, four or six months, a year, or any other time interval.
    In step 542, one or more derived diagrams are extracted from the produced PEM, generated by the reservoir simulator, at real diagram or pseudo-diagram locations, as the trajectory of the pseudo-diagrams is vertical or substantially vertical and is located in the vicinity immediately surrounding the actual trajectory of the well. For example, the actual diagrams are collected using a downhole tool, the extracted diagrams are obtained from locations of diagrams determined a priori in the PEM calculated by the reservoir simulation model and the pseudo-diagrams are derived from spatial locations defined by a user in the PEM calculated by the reservoir simulation model (for example, in step 542). The one or more derived diagrams may include, but are not limited to, one or more impedance diagrams, density diagrams, and velocity diagrams.
    In step 544, one or more estimated control wavelets are estimated based, at least in part, on the seismic control data. One or more synthetic seismic control traces are generated based, at least in part, on one or more of the diagrams derived from the PEM. An iterative estimate of the wavelets of
    2016-IPM-099958-U1-EN 18 control for seismic control data is carried out on the basis, at least in part, of one or more diagrams derived from the PEM. For example, phase and amplitude spectra from real and pseudo-derivative location diagrams from PEM or fluid substitution can be used to determine the estimated one or more wavelets of control.
    In step 546, the generated synthetic seismic control traces are compared to the control seismic prospecting. The seismic control survey is carried out on the same area as that used for the basic seismic data acquired in step 500 in order to assess the changes in the reservoir resulting from a production operation. If the synthetic seismic traces correspond to the control seismic prospecting, then in step 548 a seismic inversion of the control seismic prospecting is carried out. In step 550, it is determined whether the inversion of the seismic control survey corresponds to the PEM. For example, a three-dimensional geocell comparison or correlation of the reverse control seismic prospecting and the PEM from the flow simulation can be performed, the degree of correlation being in terms of description of amplitude of impedance and of spatial distribution between reverse control seismic and PEM. If a match appears, in step 552, at least one of one or more operations to prepare or produce a well can be changed, for example, but not limited to, production planning, rate production, an unexploited producing area, the planning or workflow of a well, the frequency of seismic acquisition or any other parameter or operating condition of the environment of a well. drilling can be modified, changed, updated or otherwise manipulated for a given site, for example the borehole environments 100 and 200 in Figures 1 and 2, respectively. For example, seismic monitoring can indicate that additional oil production is available from a current wellbore, or that one or more other wells can be drilled to obtain additional production. of hydrocarbon. In one or more embodiments, a schedule for plugging, repackaging, abandoning, or any combination thereof can be created, modified, or changed based, at least in part, on seismic monitoring.
    If a match does not appear, then in step 554 it is determined whether the flow simulation model of step 530 should be revised. The determination that the
    2016-IPM-099958-U1-EN 19 flow simulation model to be revised may be based, at least in part, on one or more factors. The one or more factors may include, but not be limited to, a similarity in the description of impedance for PEM and reverse seismic control (in regions containing a tank or not containing a tank), and putting it implementing a comparison between predicted production and actual production from the simulated period. If it is determined that the flow simulation model does not need to be revised, then the process continues at step 538 taking into account the differences in amplitude of impedance and spatial distribution.
    If it is determined that the flow simulation forecast model is to be revised in step 554, then in step 556 the flow simulation model is revised. For example, one or more of the petrophysical model, the description of rock-fluid, the pressure, the volume, the temperature and the water level are modified. In step 558, the PEM is revised. For example, the elastic model can be modified by changing one or more elastic properties such as, but not limited to, the mineral compression modulus, the shear modulus and the density of the matrix. These one or more elastic properties which are modified are inputs for the petroelastic model. As soon as the PEM is revised in step 558, the process continues to step 550.
    In step 546, if the generated synthetic seismic monitoring traces do not correspond to the monitoring seismic survey, then in step 560 it is determined whether the seismic inversion of the monitoring seismic monitoring should be revised. For example, the seismic inversion can be revised if the simulated production which was previously planned corresponds to the actual production coming from the field during a given elapsed time. In step 560, if the seismic inversion is to be revised, then in step 562 the seismic inversion is revised and the process continues to step 546. The seismic inversion can be revised based, at least in part, an adjustment of the wavelet or an update of the link from the well to the seismic. If it is determined that the seismic inversion does not need to be revised, then in step 564, it is determined whether the PEM should be revised. For example, the PEM can be revised based, at least in part, on differences in overload, underload or lateral impedance that exist in the PEM but not in the seismic inversion, which are parasites given the system modeled in tank simulators. If the PEM is to be revised, then the process continues at step 558. If the PEM does not need to be revised, then the process continues at step 548.
    2016-IPM-099958-U1-FR 20
    Although one or more aspects of this disclosure are discussed with respect to seismic data associated with a wellbore environment, this disclosure contemplates that one or more embodiments may include the use of one or more several steps of FIGS. 5A and 5B with geospatial imagery, for example.
    In one or more embodiments, a method of determining one or more operations for an underground formation comprising receiving first seismic data from an area of the underground formation, in which the first seismic data are associated with a first instance of time, the estimation of one or more wavelets on the basis, at least in part, of the first seismic data, the generation of one or more synthetic seismic traces on the basis, at least in part, of the or several estimated wavelets, the implementation of a seismic inversion using one or more spatial constraints determined on the basis, at least in part, of the first seismic data, the creation of a flow simulation forecast model, acquisition of seismic control data, generation of a petro-elastic model (PEM) based, at least in part, on an acquisition rate of the seismic control data, the estimation of one or more estimated control wavelets on the basis, at least in part, of the seismic control data, the generation of one or more synthetic seismic traces of control on the basis, at least in part, of one or more diagrams derived from the PEM, the comparison of one or more synthetic seismic traces of control to a seismic prospecting of control and the modification of one or more preparation operations or producing a well based, at least in part, on the comparison. In one or more embodiments, the method further includes placing the first seismic data in a common pool and generating a single seismic image based on the common pool, in which the estimated wavelet is based, at least in part, on the only seismic image. In one or more embodiments, the method further comprises comparing the one or more synthetic seismic traces generated with the seismic data and estimating at least a second wavelet, wherein the generation of the one or more synthetic seismic traces is based on the at least second wavelet. In one or more embodiments, the method further includes comparing the one or more synthetic seismic traces to the first seismic data to determine whether the one or more synthetic traces are within a predetermined threshold of the first seismic data . In one or more embodiments, the method further comprises implementing a petrophysical analysis and an analysis of
    2016-IPM-099958-U1-EN 21 rock physics, the generation of one or more drilling reports based, at least in part, on petrophysical analysis and on rock physics analysis, l elimination of one or more parasitic data points from one or more drilling reports and the creation of a subset of one or more drilling reports by standardizing one or more drilling reports. In one or more embodiments, the method further includes generating a fine-scale geocellular stratigraphic grid based, at least in part, on a stratigraphic frame, in which the stratigraphic frame incorporates at least one of or several spatial constraints and the blocking of the seismic inversion on the fine-scale geocellular stratigraphic grid. In one or more embodiments, the method further comprises constraining a petrophysical property model by a deposition facies model based, at least in part, on a lithotype proportion map and in which the flow simulation model is created based, at least in part, on the petrophysical property model.
    In one or more embodiments, a non-transient computer-readable storage medium storing one or more instructions which, when executed by a processor, cause the processor to receive first seismic data from an area of the underground formation, in which the first seismic data are associated with a first time instance, estimating one or more wavelets on the basis, at least in part, of the first seismic data, generating one or more synthetic seismic traces on the basis, at least in part, one or more estimated wavelets, implement a seismic inversion using one or more spatial constraints determined on the basis, at least in part, of the first seismic data, create a flow simulation forecast model, acquire seismic data control, generate a petroelastic model (PEM) on the base, at least in pa rtie, of an acquisition rate of the seismic control data, estimate one or more estimated wavelets of control on the basis, at least in part, of the seismic control data, generate one or more synthetic seismic traces of control on the basis , at least in part, from one or more diagrams derived from the PEM, compare the one or more synthetic seismic traces of control with a seismic prospecting control, and modify one or more operations of preparation or production of a well based, at least in part, on the comparison. In one or more embodiments, the one or more instructions which, when executed by the processor, further cause the processor to place the first seismic data in a common pool and generate a single seismic image based on the common pool , in
    2016-IPM-099958-U1-FR 22 which the estimated wavelet is based, at least in part, on the single seismic image. In one or more embodiments, the one or more instructions which, when executed by the processor, further cause the processor to compare the one or more synthetic seismic traces generated with the seismic data and estimate at least a second wavelet, in which generation of one or more synthetic seismic traces is based on the at least second wavelet. In one or more embodiments, the one or more instructions which, when executed by the processor, further cause the processor to compare the one or more synthetic seismic traces to the first seismic data in order to determine whether the one or more traces synthetics are within a predetermined threshold of the first seismic data. In one or more embodiments, the one or more instructions which, when executed by the processor, further cause the processor to implement a petrophysical analysis and a physics analysis of the rocks, generate one or more drilling reports based, at least in part, on petrophysical and rock physics analysis, eliminate one or more stray data points from one or more drilling reports and create a subset of the one or more reports drilling by standardizing one or more drilling reports. In one or more embodiments, the one or more instructions which, when executed by the processor, further cause the processor to generate a fine-scale geocellular stratigraphic grid based, at least in part, on a frame stratigraphic, in which the stratigraphic framework incorporates at least one of the one or more spatial constraints and block the seismic inversion on the fine-scale geocellular stratigraphic grid. In one or more embodiments, the one or more instructions which, when executed by the processor, further cause the processor to constrain a petrophysical property model by a model of deposition facies on the base, at least in part , a lithotype proportion map and in which the flow simulation model is created based, at least in part, on the petrophysical property model.
    In one or more embodiments, an information manipulation system includes a memory, a processor coupled to the memory, wherein the memory includes one or more instructions executable by the processor to receive first seismic data from an area underground formation, in which the first seismic data are associated with a first instance of time, estimating one or more wavelets on the basis, at least in part, of the first seismic data, generating one or more synthetic seismic traces on the base, at least in part, from one or
    2016-IPM-099958-U1-EN 23 several estimated wavelets, implement a seismic inversion using one or more spatial constraints determined on the basis, at least in part, of the first seismic data, create a simulation prediction model flow, acquire seismic control data, generate a petro-elastic model (PEM) based, at least in part, on an acquisition rate of seismic control data, estimate one or more estimated wavelets of control on based, at least in part, on seismic control data, generate one or more synthetic seismic traces of control on the basis, at least in part, of one or more diagrams derived from the PEM, compare the one or more synthetic seismic control traces to a seismic control prospecting and modify one or more operations of preparation or production of a well on the base, to the ego ns in part, from the comparison. In one or more embodiments, the one or more instructions can also be executed by the processor in order to place the first seismic data in a common grouping and generate a single seismic image based on the common grouping, in which the estimated wavelet is based, at least in part, on the unique seismic image. In one or more embodiments, the one or more instructions are also executable by the processor in order to compare the one or more synthetic seismic traces generated with the seismic data and estimate at least a second wavelet, in which the generation of one or more synthetic seismic traces is based on the at least second wavelet. In one or more embodiments, the one or more instructions are further executable by the processor to compare the one or more synthetic seismic traces to the first seismic data to determine whether the one or more synthetic traces are within d '' a predetermined threshold of the first seismic data. In one or more embodiments, the one or more instructions are also executable by the processor in order to carry out a petrophysical analysis and a physics analysis of the rocks, generate one or more drilling reports on the base, at least in part of petrophysical analysis and rock physics analysis, eliminate one or more parasitic data points from one or more drilling reports and create a subset of one or more drilling reports by normalizing one or more drilling reports. In one or more embodiments, the one or more instructions are further executable by the processor to generate a fine-scale geocellular stratigraphic grid based, at least in part, on a stratigraphic frame, in which the stratigraphic frame incorporates at least one of the one or more spatial constraints and block the seismic inversion on the fine-scale geocellular stratigraphic grid.
    2016-IPM-099958-U1-FR 24
    Therefore, the present invention is well suited to achieve the ends and advantages mentioned as well as those inherent here. The particular embodiments disclosed above are only illustrative, since the present invention can be modified and practiced in different but equivalent ways evident to a specialist in the field and who benefits from the present teachings. In addition, there is no limitation to the construction or design details described herein, other than those described in the claims below. It is therefore obvious that the particular illustrative embodiments disclosed above can be altered or modified and all of these variations are considered within the scope and spirit of the present invention.
    A number of examples have been described. However, it will be understood that various modifications can be made. For example, the steps in Figure 5A and Figure 5B can be performed simultaneously, substantially simultaneously, in any order or not at all. Therefore, other implementations are within the scope of the following claims.
    2016-IPM-099958-U1-FR 25
    权利要求:
    Claims (14)
    [1" id="c-fr-0001]
    The claims relate to the following:
    E A method of modifying one or more operations for preparing or producing a well for an underground formation, comprising: receiving first seismic data from an area of the underground formation, in which the first seismic data are associated at a first time instance;
    the estimation of one or more wavelets on the basis, at least in part, of the first seismic data;
    generating one or more synthetic seismic traces based, at least in part, on the estimated one or more wavelets;
    the implementation of a seismic inversion using one or more spatial constraints determined on the basis, at least in part, of the first seismic data;
    the creation of a flow simulation forecast model; acquisition of seismic control data;
    generating a petro-elastic model (PEM) based, at least in part, on an acquisition rate of the seismic control data;
    the estimation of one or more estimated control wavelets based, at least in part, on the seismic control data;
    generation of one or more synthetic seismic control traces on the basis, at least in part, of one or more diagrams derived from the PEM;
    the comparison of one or more synthetic seismic traces of control with a seismic prospecting of control; and modifying one or more operations to prepare or produce a well based, at least in part, on the comparison.
    [2" id="c-fr-0002]
    The method of claim 1, further comprising: placing the first seismic data in a common pool; and generating a single seismic image based on the common pool, in which the estimated wavelet is based, at least in part, on the single seismic image.
    2016-IPM-099958-U1-FR 26
    [3" id="c-fr-0003]
    3. Method according to claim 1, further comprising:
    comparing the one or more synthetic seismic traces generated with the seismic data; and the estimation of at least a second wavelet, in which the generation of the one or more synthetic seismic traces is based on the at least second wavelet.
    [4" id="c-fr-0004]
    The method of claim 1, further comprising comparing the one or more synthetic seismic traces to the first seismic data to determine whether the one or more synthetic traces are within a predetermined threshold of the first seismic data.
    [5" id="c-fr-0005]
    5. Method according to claim 1, further comprising:
    the implementation of a petrophysical analysis and a physical analysis of rocks;
    the generation of one or more drilling reports based, at least in part, on petrophysical analysis and on rock physics analysis;
    the elimination of one or more parasitic data points from the one or more drilling reports; and creating a subset of the one or more drilling reports by standardizing the one or more drilling reports.
    [6" id="c-fr-0006]
    6. Method according to claim 1, further comprising:
    generating a fine-scale geocellular stratigraphic grid on the basis, at least in part, of a stratigraphic frame, in which the stratigraphic frame incorporates at least one of the one or more spatial constraints; and blocking the seismic inversion on the fine-scale geocellular stratigraphic grid.
    [7" id="c-fr-0007]
    7. The method of claim 1, further comprising:
    the constraint of a petrophysical property model by a deposition facies model based, at least in part, on a lithotype proportion map; and
    2016-IPM-099958-U1-EN 27 in which the flow simulation model is created based, at least in part, on the petrophysical property model.
    [8" id="c-fr-0008]
    8. A non-transient computer-readable storage medium storing one or more instructions which, when executed by a processor, cause the processor to implement one or more of the steps according to claims 1 to 7.
    [9" id="c-fr-0009]
    9. Information manipulation system comprising: a memory;
    a processor coupled to the memory, in which the memory comprises one or more instructions executable by the processor in order to:
    receiving first seismic data from an area of the underground formation, in which the first seismic data is associated with a first time instance;
    estimating one or more wavelets based, at least in part, on the first seismic data;
    generating one or more synthetic seismic traces based, at least in part, on the estimated one or more wavelets;
    implementing a seismic inversion using one or more spatial constraints determined on the basis, at least in part, of the first seismic data;
    create a flow simulation forecast model;
    acquire seismic control data;
    generating a petro-elastic model (PEM) based, at least in part, on an acquisition rate of the seismic control data;
    estimate one or more estimated control wavelets based, at least in part, on the seismic control data;
    generate one or more synthetic seismic control traces on the basis, at least in part, of one or more diagrams derived from the PEM;
    compare the one or more synthetic seismic traces of control with a seismic prospecting of control; and modify one or more operations for the preparation or production of a well based, at least in part, on the comparison.
    2016-IPM-099958-U1-FR 28
    [10" id="c-fr-0010]
    10. The information handling system according to claim 9, in which the one or more instructions can be further executed by the processor in order to:
    place the first seismic data in a common grouping; and generate a single seismic image based on the common grouping, in which the estimated wavelet is based, at least in part, on the single seismic image.
    [11" id="c-fr-0011]
    11. An information manipulation system according to claim 9, in which the one or more instructions can also be executed by the processor in order to:
    compare the one or more synthetic seismic traces generated with the seismic data; and estimating at least a second wavelet, in which the generation of the one or more synthetic seismic traces is based on the at least second wavelet.
    [12" id="c-fr-0012]
    The information manipulation system according to claim 9, wherein the one or more instructions are further executable by the processor to compare the one or more synthetic seismic traces to the first seismic data to determine whether the one or more traces synthetics are within a predetermined threshold of the first seismic data.
    [13" id="c-fr-0013]
    13. An information manipulation system according to claim 9, in which the one or more instructions can also be executed by the processor in order to:
    implement petrophysical analysis and physical analysis of rocks;
    generate one or more drilling reports based, at least in part, on petrophysical analysis and rock physics analysis;
    eliminate one or more stray data points from one or more drilling reports; and creating a subset of the one or more drilling reports by standardizing the one or more drilling reports.
    [14" id="c-fr-0014]
    14. The information handling system as claimed in claim 9, in which the one or more instructions can also be executed by the processor in order to:
    2016-IPM-099958-U1-FR 29 generate a fine-scale geocellular stratigraphic grid on the basis, at least in part, of a stratigraphic frame, in which the stratigraphic frame incorporates at least one of one or more spatial constraints; and block the seismic inversion on the geocellular stratigraphic grid at
    5 fine scale.
    2016-IPM-099958-U1-FR 1/6
    2016-IPM-099958-U1-FR 2/6
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    法律状态:
    2018-09-28| PLFP| Fee payment|Year of fee payment: 2 |
    2019-11-29| PLFP| Fee payment|Year of fee payment: 3 |
    2020-04-17| PLSC| Search report ready|Effective date: 20200417 |
    2021-05-07| RX| Complete rejection|Effective date: 20210330 |
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    PCT/US2016/065800|WO2018106257A1|2016-12-09|2016-12-09|Wavelet estimation for four-dimensional characterization of subsurface properties based on dynamic simulation|
    IBWOUS2016065800|2016-12-09|
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