| 序号 | 专利名 | 申请号 | 申请日 | 公开（公告）号 | 公开（公告）日 | 发明人 |
|---|---|---|---|---|---|---|
| 201 | Non-rotating sensor assembly for measurement-while-drilling applications | US10119586 | 2002-04-10 | US20020108784A1 | 2002-08-15 | Thomas Kruspe; Volker Krueger |
| An MWD method and apparatus for determining parameters of interest in a formation has a sensor assembly mounted on a slidable sleeve slidably coupled to a longitudinal member, such as a section of drill pipe. When the sensor assembly is held in a non-rotating position, for instance for obtaining the measurements, the longitudinal member is free to rotate and continue drilling the borehole, wherein downhole measurements can be obtained with substantially no sensor movement or vibration. This is particularly useful in making NMR measurements due to their susceptibility to errors due caused by tool vibration. In addition, the substantially non-rotating arrangement of sensors makes it possible to efficiently carry out VSPs, reverse VSPs and looking ahead of the drill bit. A clamping device is used, for instance, to hold the sensor assembly is held in the non-rotating position. The sensor assembly of the present invention can include any of a variety of sensors and/or transmitters for determining a plurality of parameters of interest including, for example, nuclear magnetic resonance measurements. | ||||||
| 202 | Application of adaptive object-oriented optimization software to an automatic optimization oilfield hydrocarbon production management system | US09312450 | 1999-05-14 | US06434435B1 | 2002-08-13 | Paulo S. Tubel; Lynn B. Hales; Randy A. Ynchausti; Donald G. Foot, Jr. |
| The systems and the methods relating to process control optimizations systems useful to manage oilfield hydrocarbon production. The systems and the methods utilize intelligent software objects which exhibit automatic adaptive optimization behavior. The systems and the methods can be used to automatically manage hydrocarbon production in accordance with one or more production management goals using one or more adaptable software models of the production processes. | ||||||
| 203 | Adaptive acoustic channel equalizer & tuning method | US09444947 | 1999-11-22 | US06434084B1 | 2002-08-13 | Roger L. Schultz |
| A method and apparatus for data communication in an oil well environment, wherein the method comprises detecting an acoustic signal transmitted along an acoustic channel, the acoustic signal being distorted from transmission through the acoustic channel, generating a transmitted data signal in response to the acoustic signal, inputting the transmitted data signal to an adaptive equalizer and adaptively equalizing the transmitted data signal to produce an equalized data signal related to the transmitted data signal by a mathematical function. The detecting step may include positioning an acoustic receiver in a communication unit along the acoustic channel. The communication unit may be positioned downhole and the adaptive equalizer may be positioned remotely relative to the communication unit or may be placed in the communication unit. The adaptive equalizer may be a frequency domain filter, a neural net adaptive equalizer or a nonlinear recurrent neural net equalizer. The acoustic signal may comprise a plurality of discrete transmissions which may be a training sequence for training the adaptive equalizer and may comprise a first discrete transmission transmitted repeatedly. The method of data communication in an oil well environment may comprise the steps of transmitting an acoustic signal from a first location along an acoustic channel, detecting the acoustic signal at a second location along the acoustic channel, generating a transmitted data signal in response to the acoustic signal, inputting the transmitted data signal to an adaptive equalizer and adaptively equalizing the transmitted data signal to produce an equalized data signal related to the transmitted data signal by a mathematical function. The transmitting step may further comprise positioning an acoustic transmitter in a first communication unit along the acoustic channel downhole or elsewhere. The method may further comprise acquiring data, generating an original data signal in response to the acquired data and inputting the original data signal to the acoustic transmitter. The acoustic signal may comprise a series of acoustic training signals for training the adaptive equalizer. The acoustic training signals may be transmitted at a predetermined time. A stored training signal may include a series of stored training data signals corresponding to the series of acoustic training signals. At least a portion of the stored training signals may be cross-correlated to the transmitted data signal. The acoustic signal may comprise a notification signal for notifying the adaptive equalizer of a training session. | ||||||
| 204 | Method and apparatus for determining potential abrasivity in a wellbore | US09511617 | 2000-02-23 | US06386297B1 | 2002-05-14 | Craig Hodges Cooley; David Alexander Curry; Leroy William Ledgerwood, III |
| A method is provided for generating an indicator of potential bit abrasion in a particular wellbore. Forensic wellbore data is obtained from at least one previously drilled wellbore which is determined to be comparable to the particular target wellbore. Typically, the comparable wellbore comprises an “offset” wellbore which is proximate the target wellbore, and which has similar geologic features. An inference engine computer program is provided which consists of executable program instructions. It is adapted to utilize a plurality of wellbore parameters, including the forensic wellbore data. The inference engine includes at least one rule matrix which defines a plurality of fuzzy sets. These fuzzy sets establish correspondence between the plurality of wellbore parameters and the indictor of potential bit abrasion. The inference engine computer program is loaded onto a data processing system. At least the forensic wellbore data is supplied as an input to the inference engine computer program. The data processing system is utilized to execute the program instructions of the inference engine computer program. This causes the application of the inputs to the inference engine computer program. The inference engine computer program produces as an output an indication of potential bit abrasion in the particular target wellbore. | ||||||
| 205 | Method of assaying downhole occurrences and conditions | US09598131 | 2000-06-21 | US06374926B1 | 2002-04-23 | William A. Goldman; Lee Morgan Smith |
| A method of assaying work of an earth boring bit of a given size and design comprises the steps of drilling a hole with the bit from an initial point to a terminal point. A plurality of electrical incremental actual force signals are generated, each corresponding to a force of the bit over a respective increment of the distance between the initial and terminal points. A plurality of electrical incremental distance signals are also generated, each corresponding to the length of the increment for a respective one of the incremental actual force signals. The incremental actual force signals and the incremental distance signals are processed to produce a value corresponding to the total work done by the bit in drilling from the initial point to the terminal point. Using such a basic work assay, a number of other downhole occurrences and/or conditions can be assayed. These include a wear rating for the type of bit, a determination of whether such a bit can drill a given interval of formation, and assessment of the abrasivity of rock drilled (which in turn can be used to modify the assays of other conditions and/or occurrences), a model of the wear of such a bit in current use, and a determination of the mechanical efficiency of the bit. | ||||||
| 206 | Toroidal choke inductor for wireless communication and control | US09769047 | 2001-01-24 | US20020036085A1 | 2002-03-28 | Ronald Marshall Bass; Harold J. Vinegar; Robert Rex Burnett; William Mountjoy Savage; Frederick Gordon Carl JR. |
| An induction choke in a petroleum well where a voltage potential is developed across the choke to power and communicate with devices and sensors in the well. Preferably, the induction choke is a ferromagnetic material and acts as an impedance to a time-varying current, e.g. AC. The petroleum well includes a cased wellbore having a tubing string positioned within and longitudinally extending within the casing. A controllable gas lift valve, sensor, or other device is coupled to the tubing. The valve sensor, or other device is powered and controlled from the surface. Communication signals and power are sent from the surface using the tubing, casing, or liner as the conductor with a casing or earth ground. For example, AC current is directed down a casing or tubing or a lateral where the current encounters a choke. The voltage potential developed across the choke is used to power electronic devices and sensors near the choke. Such induction chokes may be used in many other applications having an elongated conductor such as a pipe, where it is desirable to power or communicate with a valve, sensor, or other device without providing a dedicated power or communications cable. | ||||||
| 207 | Electrically sequenced tractor | US09916478 | 2001-07-26 | US20020029908A1 | 2002-03-14 | Duane Bloom; Norman Bruce Moore; Ronald E. Beaufort |
| A downhole drilling tractor for moving within a borehole comprises a tractor body, two packerfeet, two aft propulsion cylinders, and two forward propulsion cylinders. The body comprises aft and forward shafts and a central control assembly. The packerfeet and propulsion cylinders are slidably engaged with the tractor body. Drilling fluid can be delivered to the packerfeet to cause the packerfeet to grip onto the borehole wall. Drilling fluid can be delivered to the propulsion cylinders to selectively provide downhole or uphole hydraulic thrust to the tractor body. The tractor receives drilling fluid from a drill string extending to the surface. A system of spool valves in the control assembly controls the distribution of drilling fluid to the packerfeet and cylinders. The valve positions are controlled by motors. A programmable electronic logic component on the tractor receives control signals from the surface and feedback signals from various sensors on the tool. The feedback signals may include pressure, position, and load signals. The logic component also generates and transmits command signals to the motors, to electronically sequence the valves. Advantageously, the logic component operates according to a control algorithm for intelligently sequencing the valves to control the speed, thrust, and direction of the tractor. | ||||||
| 208 | System and method for fluid flow optimization | US09768656 | 2001-01-24 | US20020029883A1 | 2002-03-14 | Harold J. Vinegar; Robert Rex Burnett; William Mountjoy Savage; Frederick Gordon Carl JR. |
| A controllable gas-lift well having controllable gas-lift valves and sensors for detecting flow regime is provided. The well uses production tubing and casing to communicate with and power the controllable valve from the surface. A signal impedance apparatus in the form of induction chokes at the surface and downhole electrically isolate the tubing from the casing. A high band-width, adaptable spread spectrum communication system is used to communicate between the controllable valve and the surface. Sensors, such as pressure, temperature, and acoustic sensors, may be provided downhole to more accurately assess downhole conditions and in particular, the flow regime of the fluid within the tubing. Operating conditions, such as gas injection rate, back pressure on the tubing, and position of downhole controllable valves are varied depending on flow regime, downhole conditions, oil production, gas usage and availability, to optimize production. An Artificial Neural Network (ANN) is trained to detect a Taylor flow regime using downhole acoustic sensors, plus other sensors as desired. The detection and control system and method thereof is useful in many applications involving multi-phase flow in a conduit. | ||||||
| 209 | Method and apparatus for determining potential interfacial severity for a formation | US09511618 | 2000-02-23 | US06353799B1 | 2002-03-05 | Nigel Charles Meany; David Alexander Curry; Leroy William Ledgerwood, III; Craig Hodges Cooley |
| A method and apparatus are provided for generating an indicator of potential for abrupt changes in rock strength in a particular wellbore. Forensic wellbore data is obtained from at least one previously drilled wellbore which is determined to be comparable to the target wellbore. An interfacial severity computer program is provided. The program consists of executable program instructions. It is adapted to utilize a plurality of wellbore parameters, including at least one forensic wellbore data element. The interfacial severity computer program is loaded onto a data processing system. At least the forensic wellbore data, and possibly other wellbore parameter data elements, are supplied as an input to the interfacial severity computer program. The data processing system is utilized to execute program instructions of the interfacial severity computer program. This applies the inputs to the interfacial severity computer program which produces an output and indicator of the potential for abrupt changes in rock strength in the particular target wellbore. | ||||||
| 210 | Electrically sequenced tractor | US09453996 | 1999-12-03 | US06347674B1 | 2002-02-19 | Duane Bloom; Norman Bruce Moore; Ronald E. Beaufort |
| A downhole drilling tractor for moving within a borehole comprises a tractor body, two packerfeet, two aft propulsion cylinders, and two forward propulsion cylinders. The body comprises aft and forward shafts and a central control assembly. The packerfeet and propulsion cylinders are slidably engaged with the tractor body. Drilling fluid can be delivered to the packerfeet to cause the packerfeet to grip onto the borehole wall. Drilling fluid can be delivered to the propulsion cylinders to selectively provide downhole or uphole hydraulic thrust to the tractor body. The tractor receives drilling fluid from a drill string extending to the surface. A system of spool valves in the control assembly controls the distribution of drilling fluid to the packerfeet and cylinders. The valve positions are controlled by motors. A programmable electronic logic component on the tractor receives control signals from the surface and feedback signals from various sensors on the tool. The feedback signals may include pressure, position, and load signals. The logic component also generates and transmits command signals to the motors, to electronically sequence the valves. Advantageously, the logic component operates according to a control algorithm for intelligently sequencing the valves to control the speed, thrust, and direction of the tractor. | ||||||
| 211 | Method and apparatus for the optimal predistortion of an electromagnetic signal in a downhole communication system | US09779935 | 2001-06-28 | US20020000316A1 | 2002-01-03 | Mark Christopher Haase |
| A method and apparatus for communicating a desired target signal along a piping structure is provided. Because of a lossy communication path presented by the piping structure, an input signal, which is transmitted from a first location on the piping structure, is consciously predistorted prior to transmission. The amount and nature of the predistortion applied to the input signal is determined by mathematically modeling the communication path between the first location and a second location. Predistortion of the input signal results in reception of an output signal at the second location that closely approximates the desired target signal. Application of this predistortion method of communicating is described in the context of communicating in the borehole of a petroleum well. | ||||||
| 212 | Compression-pumping system comprising an alternating compression section and its process | US09404655 | 1999-09-24 | US06296690B1 | 2001-10-02 | Yves Charron |
| An alternating compression-pumping system includes at least one alternating compression-pumping section, suited to impart a pressure value to an essentially liquid fluid or to an essentially gaseous fluid, at least one pumping section suited for an essentially fluid, at least one device for separating the various phases of the fluid, provided with a level detector allowing to detect the gas-liquid interface level, valves allowing to control the flow rate of the liquid or gas phases, and a control system allowing to vary the state of the valves so as to shift the compression section from an operating mode suited for gas to an operating mode suited for liquid and vice versa. | ||||||
| 213 | Method and apparatus for controlling the position of floating rig | US09541053 | 2000-03-31 | US06278937B1 | 2001-08-21 | Shigeki Ishida; Susumu Tanaka |
| Disclosed is a system for controlling the position of a floating rig that permits holding the rig at a position optimum to an excavation riser even if a position signal of the floating rig is not received, provided that the angles of inclination at the upper and lower ends of the riser are detected. In the method of controlling the position of a floating rig, the floating rig 10 is joined to a well head 14 at the sea bottom by an excavation riser 16, and the rig 10 is driven to a corrected position by thrusters or a combination of thrusters and a propulsion system. A neural network is allowed to learn in advance the position information of the floating rig accompanying the behaving characteristics of the excavation riser. The angles of inclination at the upper and lower ends of the excavation riser are detected and a signal represent of the detected angles is supplied to the neural network so as to permit the neural network to output the information on the correction of the present position of the floating rig. Based on the position information, the correcting information that permits diminishing the angles of inclination at the upper and lower ends of the riser is calculated so as to automatically control the position of the floating rig. Where the position information of the floating rig has ceased to be received, the angles of inclination at the upper and lower ends of the excavation riser that are to be detected are supplied to the position estimating section of the rig based on the algorithm of Kalman filter so as to estimate the rig position and, thus, to perform the position control. | ||||||
| 214 | Production well telemetry system and method | US09353565 | 1999-07-14 | US06192988B1 | 2001-02-27 | Paulo Tubel |
| A downhole production well control system is provided for automatically controlling downhole tools in response to sensed selected downhole parameters. The production well having a production tubing string therein with multiple branches, i.e., zones. Communication and transmission of power (i.e. telemetry) over the production tubing string is by way of a combination of a hardwire system in the main borehole and a short hop system at the branches or laterals. Each zone includes a downhole control system and appropriate completion devices for controlling fluid flow. An acoustic or electromagnetic transceiver is associated with each control system for communication and/or transmission of power. An electrical conductor runs from the surface downhole along the production tubing string in the main borehole for communication and/or transmission of power, hardwired systems are well known. The conductor is connected to an acoustic or electromagnetic transceiver disposed at the production tubing string in the main borehole near each branch. These transceivers communicate with and/or transfer power to corresponding transceivers at the branches (i.e., short hop communications), which is communicated and/or transferred along the production tubing string on the conductor (i.e., uphole or downhole). | ||||||
| 215 | Method and apparatus for the remote control and monitoring of production wells | US09003836 | 1998-01-07 | US06192980B1 | 2001-02-27 | Paulo S. Tubel; Albert A. Mullins, II; Kevin R. Jones |
| A system adapted for controlling and/or monitoring a plurality of production wells from a remote location is provided. This system is capable of controlling and/or monitoring: (1) a plurality of zones in a single production well; (2) a plurality of zones/wells in a single location (e.g., a single platform); or (3) a plurality of zones/wells located at a plurality of locations (e.g., multiple platforms). The multizone and/or multiwell control system of this invention is composed of multiple downhole electronically controlled electromechanical devices and multiple computer based surface systems operated from multiple locations. Important functions for these systems include the ability to predict the future flow profile of multiple wells and to monitor and control the fluid or gas flow from either the formation into the wellbore, or from the wellbore to the surface. The control system of this invention is also capable of receiving and transmitting data from multiple remote locations such as inside the borehole, to or from other platforms, or from a location away from any well site. | ||||||
| 216 | Moling apparatus and a ground sensing system therefor | US09125721 | 1998-12-22 | US06176325B1 | 2001-01-23 | Albert Alexander Rodger |
| The invention provides a ground sensing system (10) comprising: sensing means (19) located, in use, on a projectile being driven through ground by means of apparatus having a self adjustment between a vibration mode and a vibro-impact mode according to encountered ground resistance, the sensing means sensing the dynamic resistance of the ground that the projectile is passing through; signal processing means for processing the output of said sensing means to provide a dynamic resistance waveform (106); and waveform recognition means (108) for correlating said dynamic resistance waveform with stored dynamic waveforms for identifying a ground characteristic. The waveform recognition means may comprise a neural network system. | ||||||
| 217 | Method for randomly accessing stored imagery and a field inspection system employing the same | US09029285 | 1998-02-26 | US06175380B1 | 2001-01-16 | Jeffrey A. Van Den Bosch |
| The present invention relates to a field inspection system (100) for compressing video signals received from a field inspection video camera (14) into compressed video data and for burning the compressed video data on a compact disc (118) along with an electronic logsheet. The electronic logsheet includes a listing of suspected defects or anomalies and associated pointers to reference frames in the compressed video data. The electronic logsheet may be displayed and an operator may access a portion of the field inspection video showing a listed defect by clicking a mouse button (116) when a pointer icon is positioned on the listed defect. To perform this task, the present invention utilizes a technique for randomly accessing the compressed video data in which reference frames included therein are used as access points to the video footage. | ||||||
| 218 | Downhole tools using artificial intelligence based control | US188509 | 1998-11-09 | US6026911A | 2000-02-22 | Colin M. Angle; Thomas W. McIntyre |
| The present invention provides a system for performing a desired operation in a wellbore. The system contains a downhole tool which includes a mobility platform that is electrically operated to move the downhole tool in the wellbore and an end work device to perform the desired work. The downhole tool also includes an imaging device to provide pictures of the downhole environment. The data from the downhole tool is communicated to a surface computer, which controls the operation of the tool and displays pictures of the tool environment. Novel tactile sensors for use as imaging devices are also provided. In an alternative embodiment the downhole tool is composed of a base unit and a detachable work unit. The work unit includes the mobility platform, imaging device and the end work device. The tool is conveyed into the wellbore by a conveying member. The work unit detaches itself from the base unit, travels to the desired location in the wellbore and performs a predefined operation according to programmed instruction stored in the work unit. The work unit returns to the base unit, where it transfers data relating to the operation and can be recharged for further operation. | ||||||
| 219 | Method of controlling development of an oil or gas reservoir | US851919 | 1997-05-06 | US6002985A | 1999-12-14 | Stanley V. Stephenson |
| A method controlling development of an oil or gas reservoir uses a neural network and genetic algorithm program to define a neural network topology and the optimal inputs for that topology. The topology is defined from identified and selected (1) parameters associated with the formation or formations in which actual wells are drilled in the reservoir and (2) parameters associated with the drilling, completion and stimulation of those wells and (3) parameters associated with the oil or gas production from the wells. Subsequent drilling, completion and stimulation of the reservoir is determined and applied based on hypothetical alternatives input to the topology and resulting outputs. | ||||||
| 220 | Conductivity anisotropy estimation method for inversion processing of measurements made by a transverse electromagnetic induction logging instrument | US42982 | 1998-03-17 | US5999883A | 1999-12-07 | Pravin Gupta; Berthold F. Kriegshauser; Otto N. Fanini |
| A method for determining an initial estimate of the horizontal conductivity and the vertical conductivity of an anisotropic earth formation. Electromagnetic induction signals induced by induction transmitters oriented along three mutually orthogonal axes are measured. One of the mutually orthogonal axes is substantially parallel to a logging instrument axis. The electromagnetic induction signals are measured using first receivers each having a magnetic moment parallel to one of the orthogonal axes and using second receivers each having a magnetic moment perpendicular to a one of the orthogonal axes which is also perpendicular to the instrument axis. A relative angle of rotation of the perpendicular one of the orthogonal axes is calculated from the receiver signals measured perpendicular to the instrument axis. An intermediate measurement tensor is calculated by rotating magnitudes of the receiver signals through a negative of the angle of rotation. A relative angle of inclination of one of the orthogonal axes which is parallel to the axis of the instrument is calculated, from the rotated magnitudes, with respect to a direction of the vertical conductivity. The rotated magnitudes are rotated through a negative of the angle of inclination. Horizontal conductivity is calculated from the magnitudes of the receiver signals after the second step of rotation. An anisotropy parameter is calculated from the receiver signal magnitudes after the second step of rotation. Vertical conductivity is calculated from the horizontal conductivity and the anisotropy parameter. | ||||||
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