| 序号 | 专利名 | 申请号 | 申请日 | 公开（公告）号 | 公开（公告）日 | 发明人 |
|---|---|---|---|---|---|---|
| 101 | Tuyau souple comportant des moyens de détection visuelle précoce d'un dysfonctionnement et ses brides d'extrémites | EP94102204.8 | 1994-02-23 | EP0614034B1 | 1997-06-04 | Ragout, Bernard; Mayau, David; Moreau, Charles |
| 102 | Anordnung zur Energie- und Messwertübertragung von einer Zentralstation auf mehrere Messstellen | EP80104931.3 | 1980-08-20 | EP0028296B1 | 1986-11-12 | Kranert, Klaus, Dr.-Ing.; Schröder, Michael, Ing.grad. |
| 103 | RISER ANGLE POSITIONING SYSTEM AND PROCESS | EP81900882.0 | 1981-02-20 | EP0046800A1 | 1982-03-10 | DEAN, Q. Wayne |
| Procede et systeme de positionnement d'angle d'une colonne montante fournissant des informations appropriees au positionnement dynamique d'un bateau (10) ayant une colonne (12) s'etendant jusqu'a la tete d'un puits sur le fond de l'ocean. Le systeme comprend un systeme acoustique (46) pour produire des signaux de donnees acoustiques representant la position du bateau par rapport a la tete du puits, des inclinometres du haut (42) et du bas (44) de la colonne pour produire des signaux detecteurs respectifs indiquant les angles de deflexion de la colonne a sa partie superieure et a sa partie inferieure respectivement, et un processeur (40) sensible aux signaux de donnees acoustiques et aux signaux detecteurs pour produire des informations de positionnement. Le procede et le systeme de positionnement d'angle de la colonne servent de systemes de reserve et de procedes de controle des donnees acoustiques en cas d'erreurs importantes, et fournissent en plus le seul systeme de determination de position en cas de suppression acoustique. Le systeme et le procede de positionnement d'angle de la colonne possedent deux modes alternatifs de fonctionnement: un mode simulateur pendant lequel la position du bateau est calculee a l'aide de donnees lues depuis une bande magnetique d'enregistrement d'un systeme de positionnement dynamique, et un mode en temps reel pendant lequel les donnees sont lues directement a partir de convertisseurs analogiques/numeriques associes aux inclinometres superieur (42) et inferieur (44) et au systeme acoustique (46). | ||||||
| 104 | Seal Integrity Verification System for Riser Deployed RCD | US16334338 | 2016-10-18 | US20190211666A1 | 2019-07-11 | Richard David Peer; Christopher Allen Grace |
| A system, method, and rotating control device (RCD) for monitoring a condition of a sealing element engageable with a body of the RCD. The system comprises a riser assembly, the RCD body, the sealing element, a latch assembly, a measurement device, and a controller. The RCD body is connectable with the riser assembly and the latch assembly is locatable in the RCD body and actuatable to expand the sealing element to engage the RCD body. The measurement device is operable to measure a parameter indicative of a condition of the sealing element. The controller is operable to analyze the parameter to identify the condition of the sealing element. The method for monitoring a condition of the sealing element comprises measuring the parameter indicative of the condition of the sealing element with the measurement device; and analyzing the parameter to identify the condition of the sealing element with the controller. | ||||||
| 105 | Kick detection systems and methods | US14735273 | 2015-06-10 | US10151159B2 | 2018-12-11 | Emanuel J. Gottlieb; Donald S. Coonrod; Donald R. Augenstein |
| An apparatus for detecting potential kicks in a well is provided. In one embodiment, the apparatus includes a drill string positioned in a well, a mud circulation system coupled to supply drilling mud to the drill string, and a mud analyzer. The mud analyzer includes a sensor that is positioned along a drilling mud return path closer to a wellhead assembly installed at the well than to a mud tank of the mud circulation system, and the mud analyzer enables identification of a potential formation kick based on data acquired by the sensor. Additional systems, devices, and methods are also disclosed. | ||||||
| 106 | SYSTEMS AND METHODS FOR MONITORING SUBSEA WELLHEAD SYSTEMS | US15476197 | 2017-03-31 | US20180283162A1 | 2018-10-04 | Derrell Wade Bird; Chad Eric Yates |
| A system includes a wellhead monitoring system. The wellhead monitoring system includes a processor configured to receive from a sensor a detection of one or more operating parameters associated with a wellhead disposed within a subsea environment. The sensor is coupled to the wellhead, and is configured to detect the one or more operating parameters within the subsea environment. The processor is configured to store the detection of the one or more operating parameters, and to generate an output based at least in part on the detection of the one or more operating parameters. The output includes an indication of an operational fatigue or an operational health of the wellhead. | ||||||
| 107 | Device For In-Line Monitoring Of The Quality Of A Water-Soluble Polymer Solution Manufactured From Invert Emulsion Or Powder Of Said Polymer | US15557417 | 2016-03-09 | US20180275037A1 | 2018-09-27 | Cedrick Favero; Christophe Rivas |
| An apparatus for monitoring the effective dissolving of a polymer when the use region is not accessible. The apparatus includes a pipe on which are inserted, consecutively: a pump, a flowmeter, a water or brine inlet mechanism for diluting the mother solution flowing in the pipe, a mixer capable of in-line homogenization of the diluted mother solution, a first tube calibrated to simulate the distance and the conditions for moving the diluted solution in the main pipe between the point where the mother solution is diluted and the use region, a mechanism capable of reducing the pressure of the diluted solution flowing in the pipe upstream of the first tube that is calibrated from 10 to 10000 kPa (from 0.1 to 100 bar), a second calibrated tube for creating a head loss, and a device for measuring differential pressure between the inlet and the outlet of the second calibrated tube. | ||||||
| 108 | DRILLING OR WORK-OVER RIG COMPRISING AN OPERATIONAL CONTROL AND/OR STATE UNIT AND A COMPUTER-IMPLEMENTED METHOD OF PROVIDING OPERATIONAL CONTROL AND/OR STATE | US15763099 | 2016-09-26 | US20180274338A1 | 2018-09-27 | John Røn Pedersen; Jesper HOLCK |
| a drilling or work-over vessel (10) is disclosed comprising a number of operational equipment (300), wherein the drilling or work-over vessel comprises at least one operational control and/or state unit (100) comprising at least one processing unit (102), wherein the at least one operational control and/or state unit (100) comprises or are in connection with a memory and/or storage (103), and at least one sensor unit (200), wherein the at least one sensor unit (200) is adapted to obtain one or more measured physical values and to provide data representing the one or more measured physical values and/or derived values thereof to the at least one operational control and/or state unit (100), the memory and/or storage (103) comprises a data representation of a computational physics model of at least a part of the drilling or work-over rig, and the at least one processing unit (102) is adapted to derive data representing an estimation of one or more physical states (such as defined by limits of forces, relative motion between operational equipment and vessel, or between other two pieces of operational equipment) estimated to act on at least one operational equipment (300) in response to the data representing the one or more measured physical values and/or derived values thereof as provided by the at least one sensor unit (200). | ||||||
| 109 | Downhole pressure maintenance system using reference pressure | US14916328 | 2015-01-13 | US10024147B2 | 2018-07-17 | Syed Hamid; Tyson Harvey Eiman; Gregory William Garrison; Colby Munro Ross; William Mark Richards; Thomas Jules Frosell |
| A method and apparatus that includes an elongated base pipe having an external surface at least partially defining an external region and an internal surface at least partially defining an internal region; and a pressure maintenance device disposed in the base pipe and includes a first flow path that extends between an opening in the external surface and an opening in the internal surface; a first valve that controls the flow of a first fluid through the first flow path; a first pressure differential sensor that controls the actuation of the first valve and is in fluid communication with the external region; and a pressurized fluid source in fluid communication with the first pressure differential sensor; wherein a first pressure differential threshold associated with the first pressure differential sensor is the difference between a pressure within the external region and the pressurized fluid source. | ||||||
| 110 | PORCH MOUNTED VARIABLE RELUCTANCE MEASUREMENT TECHNOLOGY TENDON TENSION MONITORING SYSTEM | US15839436 | 2017-12-12 | US20180162491A1 | 2018-06-14 | John Ray Baileys; Michael Eugene Hogan; Joseph Michael O'Neil; Daniel Joseph Tye |
| The invention relates to floating platform mooring and involves an improved platform mounted tendon tension monitoring system with porch-mounted variable reluctance measurement technology sensors configured. The variable reluctance measurement technology sensors of this system are optimized for porch mounting. The porch-mounted tendon tension monitoring system can also be configured such that the porch-mounted optimized variable reluctance measurement technology sensors are replaceable. Sensors may be replaced to extend the desired useful lifetime of a tendon tension monitoring system or in the event that a sensor happens to malfunction. A plurality of variable reluctance measurement technology sensors can be configured in sensor packs at the corners or at other locations where tendon tension monitoring can be useful for a floating platform. | ||||||
| 111 | INTEGRATED WELL SYSTEM ASSET AND HIGH INTEGRITY PRESSURE PROTECTION | US15368196 | 2016-12-02 | US20180156004A1 | 2018-06-07 | Bilal HUSSAIN; Stephen MAY; Joseph WILHELMI |
| A technique facilitates integration of a well system asset, e.g. a subsea asset, with a pressure protection system (PPS) to prevent over-pressurization on a downstream side of the well system asset. The PPS comprises a barrier structure which may be automatically actuated upon sensing the over-pressurization to block further flow through the well system asset. By combining the PPS and the asset into an integrated structure, certain internal components and functionality may be shared. The integrated structure provides a substantially smaller footprint on, for example, the seabed while also providing a more cost efficient structure to construct and deploy. | ||||||
| 112 | Managed pressure cementing | US15011750 | 2016-02-01 | US09951600B2 | 2018-04-24 | Don M. Hannegan; Cesar Pena; David Pavel; Michael Brian Grayson; Said Boutalbi; Todd Douglas Cooper; Timothy P. Dunn; Frank Zamora, Jr. |
| A method of cementing a tubular string in a wellbore includes: deploying the tubular string into the wellbore; pumping cement slurry into the tubular string; launching a cementing plug after pumping the cement slurry; propelling the cementing plug through the tubular string, thereby pumping the cement slurry through the tubular string and into an annulus formed between the tubular string and the wellbore; and controlling flow of fluid displaced from the wellbore by the cement slurry to control pressure of the annulus. | ||||||
| 113 | Monitoring tubing related equipment | US14958231 | 2015-12-03 | US09932815B2 | 2018-04-03 | Kirk Flight; John Yarnold; Matthew Niemeyer; Jeffrey Marabella |
| A technique facilitates monitoring of strain related effects along a tubing string, such as a tubing string extending from surface equipment toward a sea floor in a subsea well application. A monitoring module is employed to monitor the strain related effects and may have a tubular structure. The monitoring module also has a reduced wall thickness region constructed to concentrate strain in this reduced wall thickness region. Additionally, the monitoring module comprises at least one sensor mounted to the tubular structure in the reduced wall thickness region for monitoring of strains. | ||||||
| 114 | METHODS AND SYSTEMS EMPLOYING A CONTROLLED ACOUSTIC SOURCE AND DISTRIBUTED ACOUSTIC SENSORS TO IDENTIFY ACOUSTIC IMPEDANCE BOUNDARY ANOMALIES ALONG A CONDUIT | US15569464 | 2015-05-29 | US20180087372A1 | 2018-03-29 | Christopher Lee Stokely; John L. Maida; Neal Gregory Skinner; Andreas Ellamauthaler |
| A system includes a controlled acoustic source. The system also includes distributed acoustic sensors along a conduit. The distributed acoustic sensors obtain acoustic signal measurements as a function of position along the conduit in response to at least one acoustic signal provided by the controlled acoustic source. The system also includes a processing unit that generates an acoustic activity plot or report based on the acoustic signal measurements. The acoustic activity plot or report is used to identify at least one acoustic impedance boundary anomaly as a function of position along the conduit. | ||||||
| 115 | CONDUIT FATIGUE MANAGEMENT SYSTEMS AND METHODS | US15703132 | 2017-09-13 | US20180080850A1 | 2018-03-22 | Phillip Adam Rice; Robert Stewart James Large; Andrew Edward Heaney; Bernard Theron |
| A technique facilitates monitoring and managing fatigue related a flexible conduit deployed from a surface vessel. Movements of the surface vessel may be measured to obtain vessel movement/position data. Based on this data, a flexible conduit bend profile may be determined via a computer-based data processing system. The flexible conduit bend profile may then be used to provide a flexible conduit fatigue profile for assessment of the flexible conduit in light of the environmental conditions. In some embodiments, the fatigue profile and assessment of the flexible conduit may be based on both functional loading and environmental loading. | ||||||
| 116 | METHOD FOR DETERMINING AN OPERATIONAL STATE OF A SUBSEA CONNECTOR UNIT | US15558781 | 2016-03-21 | US20180076573A1 | 2018-03-15 | Daniel Walton |
| A method for determining an operational state of a subsea connector unit, wherein the method includes: providing at least one operational value and/or a plurality of operational values of at least one operational parameter describing a specific operational condition at at least one selected location of the subsea connector unit and comparing the at least one provided operational value and/or the plurality of provided operational values and/or at least one derivative derived from the at least one provided operational value and/or at least one derivative derived from the plurality of provided operational values with at least one predefined reference and thus determining an operational state of the subsea connector unit on the basis of the comparison. An assembly monitors an operational state of a subsea connector unit and a subsea connector unit has the assembly. | ||||||
| 117 | EROSION MANAGEMENT SYSTEM | US15556674 | 2016-03-11 | US20180051549A1 | 2018-02-22 | Simon Charles HOLYFIELD |
| An erosion management system is configured to monitor erosion of a component of a mineral extraction system. The erosion management system includes a controller configured to receive feedback from a flow meter related to a flow rate of a production fluid flowing through the component. Additionally, the controller is configured to receive feedback from an erosion detector related to an amount of solids in the production fluid. The controller is configured to determine an erosion rate of the component based on the feedback from the flow meter and the feedback from the erosion detector. | ||||||
| 118 | Detection of influxes and losses while drilling from a floating vessel | US14421369 | 2012-10-05 | US09874081B2 | 2018-01-23 | Neal G. Skinner |
| A system for detecting fluid influxes and losses can include a sensor which detects floating vessel movement, and a neural network which receives a sensor output, and which outputs a predicted flow rate from a wellbore. A method can include isolating the wellbore from atmosphere with an annular sealing device which seals against a drill string, inputting to a neural network an output of a sensor which detects vessel movement, the neural network outputting a predicted flow rate from the wellbore, and determining whether the fluid influx or loss has occurred by comparing the predicted flow rate to an actual flow rate from the wellbore. Another method can include inputting to a neural network actual flow rates into and out of the wellbore, and an output of a sensor which detects vessel movement, and training the neural network to output a predicted flow rate from the wellbore. | ||||||
| 119 | Monitoring hydrocarbon fluid flow | US15227457 | 2016-08-03 | US09840904B2 | 2017-12-12 | Raymond Phillips; Nicholas Josep Ellson |
| A christmas tree assembly for a subsea hydrocarbon extraction facility, the christmas tree assembly includes a fluid pipeline and a sensor assembly comprising a plurality of sensors configured to monitor a plurality of properties relating to hydrocarbon fluid flow through the fluid pipeline. The sensor assembly includes a differential pressure sensor that is disposed at one or more of across a choke, around a bend or restriction in the pipeline or a dedicated flow restrictor integrated within the pipeline, and a bulk density sensor that is disposed in one or more of a blind T, before or after a choke or in an upwards section of the flow pipeline. | ||||||
| 120 | Method for predicting hydrate formation | US15317119 | 2015-05-21 | US09828847B2 | 2017-11-28 | Dag Vavik |
| A method for predicting a formation of hydrates in a wellbore/riser annulus during a drilling operation. The method includes logging actual mud properties. Actual sets of pressure and temperature data at given locations/intervals in the wellbore or in the drilling riser annulus are continuously measured and/or calculated. A theoretical temperature profile for the formation of hydrates dependent on mud properties and pressure as a function of a true vertical depth in a well is determined. The theoretical temperature profile for the formation of hydrates in a control system is stored. The measured and/or calculated actual sets of pressure and temperature data is compared with the theoretical temperature profile for the formation of hydrates. A signal is issued if the measured and/or calculated actual sets of pressure and temperature data falls below or is lower than a predefined safety margin for the theoretical temperature profile for the formation of hydrates. | ||||||
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