Abstract: The trip system closely monitors and ensures that the hydrostatic pressure of the wellbore stays consistent throughout the tripping process, stripping process, and axial pipe operations. The core components of the system include, but are not limited to, an advanced automation system that controls a back-pressure device, including but not limited to a choke, a rotary ball valve, or other flow control devices. The automation system also monitors upstream and downstream flow measurement components. The trip system also provides a pump system to circulate drilling fluid from the trip tank across the top of the wellhead and/or at a lower portion below the RCD.

Abstract: The disclosure relates to an automatic measuring system and a method thereof for drilling fluid parameters measurement. The system includes i. mud container, configured for test drilling fluid preparation and samples collection; ii. heat jacket, configured to keep the drilling fluid in the tank warm iii. heat exchanger, configured to simulate the practical conditions; iv. plunger pump, configured to pump the test drilling fluid to the flowing test device; v. flow test device, configured to simulate the flowing states of drilling fluid in the borehole annulus and drilling string, and also measure the pressure and flow rate of drilling fluid vi. control module, configured to obtain rheological parameters and the best rheological mode of the drilling fluid in the borehole annulus and drilling string based on the pressure and flow rate.

Abstract: A control system for a pressure management apparatus (PMA) of a drilling system has an onsite device in close proximity to and in communication with the PMA and an offsite device at a remote location. Both the onsite and offsite devices are connected to a network, such as the Internet, through which the devices can communicate with one another. The onsite device receives data in real-time from the PMA and the offsite device can access the data in real-time via the network. The offsite device can generate a command based on the data or user input at the offsite device and send the command to the onsite device to modify one or more settings of the PMA. A control panel is displayed on the user interface of the offsite device to allow an operator to remotely control the PMA.

Abstract: The flow of well mud being pumped by a drilling rig pump into a wellbore is sensed by monitoring at least one signal from at least one sensor of drilling mud, determining a total well drilling pump mud output rate, and determining an apparent annular mud rate based on the at least one signal and the total pump drilling rate.

Abstract: A system is disclosed for measuring fluid flow. The system may include a plurality of sensors and a computing device. The plurality of sensors may be positionable at different angles in a container of an offshore drilling rig to sense data about drilling fluid flow in the container. The computing device may be communicatively couplable to the plurality of sensors for receiving the data about the drilling fluid flow in the container and using the data to determine a calculated fluid flow rate compensating for movement of the offshore drilling rig.

Abstract: The trip system closely monitors and ensures that the hydrostatic pressure of the wellbore stays consistent throughout the tripping process, stripping process, and axial pipe operations. The core components of the system include, but are not limited to, an advanced automation system that controls a back-pressure device, including but not limited to a choke, a rotary ball valve, or other flow control devices. The automation system also monitors upstream and downstream flow measurement components. The trip system also provides a pump system to circulate drilling fluid from the trip tank across the top of the wellhead and/or at a lower portion below the RCD.

Abstract: The present invention relates to a system for contaminant extraction in a borehole extending from a surface of the Earth through a water permeable layer and into an underlying production zone, the system comprising: an outer casing located within the borehole and extending through the water permeable layer; a production pipe located within the casing and extending towards the production zone; a filter assembly occupying at least part of an intermediate zone between the outer casing and the production pipe, wherein the filter assembly is configured to capture contaminants before they enter the water permeable layer and/or before they are released into the atmosphere, the filter assembly comprising: a lower solids filtering stage configured to filter solid contaminants; and an upper fluids filtering stage configured to filter fluid contaminants migrating from the production zone through the lower solids filtering stage; and sealing means for preventing the uncontrolled leakage of contaminants from the intermedi

Abstract: Mud return flow measurements are made from multiple locations using radar-based surface level sensors. Using the inputs from two different sensors on the drilling mud return line provides the ability to calculate the actual flow based on pipe geometry, the speed of the surface of the fluid and parameters such as fluid viscosity and density.

Abstract: A fluid outflow measurement system and a method are disclosed for fluid flow determination that measures and determines fluid flow and retains consistent high-sensitivity and high-accuracy performance throughout the measurement range of zero flow to maximum flow. The fluid outflow measurement system and method adds a fluid height measurement from a sensor mounted on the vertical stack or bell nipple section of a drilling rig. The vertical stack or bell nipple section is a location where a change of flow, manifested by a change in fluid height, is more detectable and makes the overall flow more sensitive throughout zero to maximum flow range, especially at low flows (resulting in better curve shape definitions of flow back signatures) and to subtle flow changes due to micro influxes or losses.

Abstract: A communication system 100) comprises a first set (204, 206) of transducers and a second set (210, 212) of transducers. The system further comprises a first signal processing device (106) configured to produce a signal for transmission by at least some of the transducers in the first set to at least some of the transducers in the second set, and a second signal processing device (110) configured to process signals received from at least some of the transducers in the second set in order to select a best said signal that is used for further processing. The first set of transducers comprises a first subset (204) comprising at least one said transducer, and a second subset (206) comprising at least one said transducer. Transducers in the first subset transmit on a first channel and transducers in the second subset transmit on a second channel having a different frequency.

Abstract: Disclosed is a method and apparatus for determining an ablation modulus of a mudcake on a wellbore wall. According to various embodiments of the invention, the method includes preparing a mudcake, forming a mudcake assemblage comprising the prepared mudcake, screen, and a filter paper, and submerging and securing the mudcake assemblage in a container filled with a fluid. The fluid includes one of a native fluid and a foreign fluid to the mudcake. The method further includes agitating the fluid for a plurality of time intervals, removing the mudcake assemblage from the container after expiration of each time interval, and drying the mudcake assemblage. Further, the method includes weighing the mudcake assemblage to determine an interval weight for each time interval, and determining the ablation modulus of the mudcake on the wellbore wall by graphically correlating the determined interval weights of the remaining mudcake in the mudcake assemblage as a function of time.

Abstract: The present invention includes a device and method for determining the flow of one or more phases of a multiphase fluid mixture comprising: a tube, a pipe, a main body or any combinations thereof comprising an interior and an exterior, wherein the interior receives a multiphase fluid mixture for the determination of the fractions in the multiphase; a first ultrasound field detector ring comprising: two or more pairs of transversal paired dual frequency ultrasound transmitter/receivers are on the same normal plane and are positioned in a transversal direction to a flow of the multiphase fluid mixture on the exterior of the tube, pipe, or main body, wherein the sampled volume covers a part of or the whole cross-section of the flow volume; and a computer connected to the ultrasound transmitter/receivers that determines the one or more phases of a multiphase fluid mixture.

Abstract: A method for characterizing a subsurface formation using a fluid pressure response during wellbore drilling operations includes the steps of determining a change in wellbore pressure proximate the surface, calculating a change in volumetric flow rate out of the wellbore as a function of the change in wellbore pressure proximate the surface, determining a downhole fluid pressure in the wellbore corresponding to the change in wellbore pressure proximate the surface and determining a productivity index value as a function of the change in volumetric flow rate, the downhole fluid pressure and a reservoir pressure.

Abstract: An apparatus for use in a wellbore having a housing having at least one chamber capable of receiving a fluid, a sealed annular volume, and a non-electronic pressure sensor disposed in the sealed annular volume. The non-electronic sensor includes a sealed, compressible container. Positioned within the sealed, compressible container are first and second magnets that are separated by a first distance when a fluid within the sealed annular volume is at a first pressure. When the fluid in the sealed annular volume is at a second pressure, the first and second magnets are separated by a second distance.

Abstract: A capacitive pressure sensor includes a stator which encircles a portion of a cylindrical diaphragm. This encircling forms a circumferential gap between the sidewalls of the stator and the diaphragm. Therefore, a greater area “A” can be achieved in smaller diameter sensor footprint than prior art designs and yet still detect relatively small changes in capacitance. Additionally, the width “g1” of the gap can be wider than prior art designs without negatively affecting capacitance detection. A bonding agent which has a melting temperature of about half that of bonding agents used in prior art designs, secures the stator to the diaphragm and reduces oxidation issues during assembly, thereby decreasing manufacturing time and cost. To ensure proper side-to-side alignment of the stator relative to the diaphragm, a centering sleeve, which is removed after bonding, is placed over as stub at the upper end of the diaphragm.

Abstract: A system includes one or more sensors configured to sense at least one characteristic of fluid entering a well, one or more sensors configured to sense at least one characteristic of fluid exiting a well; and one or more control systems that receive data from at least one of the sensors.

Abstract: Flowmeters and methods of measuring a fluid flow or manufacturing flowmeters are presented. A flowmeter has a tool body and one or more spinner arms configured to extend with a first end away from the tool body and a second end joined to the tool body, when deployed to measure a fluid flow. Each spinner arm includes a helical blade configured to rotate due to a fluid flowing substantially parallel to a longitudinal axis of the tool body, around a rotation axis between the first end and the second end.

Abstract: A method of identifying a self-sustained influx of formation fluids into a wellbore includes the steps of closing an annular shut-off device and diverting an annular return flow from the wellbore through a first flow rate measurement device, measuring a flow rate of said annular return flow, measuring an inlet flow rate of fluids entering the well through a second flow rate measurement device in a fluid injection line, and identifying a self-sustained influx of formation fluids if a non-decreasing measured annular return flow rate is greater than said measured inlet flow rate.

Abstract: A production monitoring system (10) comprises a plurality of injection and production units (80) coupled in operation to sensors (410) for measuring physical processes occurring in operation in the injection and production units (80) and generating corresponding measurement signals (420) for computing hardware (400). The computing hardware (400) is operable to execute software products (300) for processing the signals (420). Moreover, the software products (300) are adapted for the computing hardware (400) to analyze the measurement signals (420) to abstract a parameter representation of the measurement signals (420), and to apply a temporal analysis of the parameters to identify temporally slow processes and temporally fast processes therein, and to employ information representative of the slow processes and fast processes to control a management process for controlling operation of the system (10).

Abstract: An apparatus for detecting fluid modulation signals transmitted by an instrument in a wellbore includes a motion sensor coupled to a selected position on an exterior of a conduit coupled between a discharge side of a fluid pump and an inlet to a pipe string suspended in the wellbore. The instrument is coupled to the pipe string. A signal detector is in signal communication with the motion sensor.

Abstract: A method is disclosed for optimal lift resource allocation, which includes optimally allocating lift resource under a total lift resource constraint or a total production constraint, the allocating step including distributing lift resource among all lifted wells in a network so as to maximize a liquid/oil rate at a sink.

Abstract: The present invention relates to an apparatus (100) suitable for use in substantially continuous measurement of a physical property particularly the rheology and/or viscosity of a drilling fluid in use thereof in a drilling fluid or mud flow circuit of a drilling device. The present invention also relates to an apparatus (100) suitable for use in substantially continuous measurement of a physical property particularly the rheology and/or viscosity of any non-newtonian fluid is use thereof. The apparatus (100) comprises of a sample chamber (26) having an inlet (7) and an outlet (9) and is arranged to allow a drilling fluid to flow therethrough from the inlet 7 to the outlet (9). Detector devices (33, 34, 35) such as Viscometers are provided for substantially continuous measurement of a physical property particularly the rheology and/or viscosity of a drilling fluid flowing thought the sample chamber (26) in use of the apparatus (100).

Abstract: A method to detect leaks in a rotating control device includes positioning a leak detection device in communication with a chamber located between an upper sealing element and a lower sealing element of the rotating control device, and signaling with the leak detection device when a pressure of the chamber exceeds a selected critical pressure.

Abstract: A method is disclosed for optimal lift gas allocation, comprising: optimally allocating lift gas under a total lift gas constraint or a total produced gas constraint, the allocating step including distributing lift gas among all gas lifted wells in a network so as to maximize a liquid or oil rate at a sink.

Abstract: Methods and apparatus are described that combine a measurement of the physical velocity of material within the annulus of a well between the drill pipe and the wall of the well with a measurement of the area of the flow as determined from a measurement of distance between the drill pipe and the wall of the hole to determine the actual material volumetric flow rate. Changes in volumetric flow rate at one or more points along the well can be used to determine the occurrence and location of well dysfunctions. This knowledge can then be used to make decisions about treating well dysfunctions which will lead to more efficient use of drilling rig time.

Abstract: Embodiments of the present invention relate in general to methods and apparatus for determining downhole mud flow rates and other downhole parameters.

Abstract: Disclosed herein is a method of detecting a downhole washout. The method includes, positioning a plurality of sensors along a downhole drillstring, communicatively coupling the plurality of sensors to a processor, and analyzing data sensed by the plurality of sensors with the processor for relationships indicative of a washout.

Abstract: A closed-loop circulating system for drilling wells has control of the flow rates in and out of the wellbore. Kicks and fluid losses are quickly controlled by adjusting the backpressure. Kick tolerance and tripping margins are eliminated by real-time determination of pore and fracture pressure. The system can incorporate a rotating BOP and can be used with underbalanced drilling.

Abstract: Device for the quantitative analysis of debris (12, 41) preferably produced during drilling, of the type equipped with means for the progressive collection of the debris, means for the progressive weighing of the debris collected, means for periodical discharging of the same and a structure for support of the device, wherein said means for the collection of the debris comprise a conveyor belt (22, 46) wound in the manner of a track on at least two rollers (23, 24), said means for weighing the debris comprise at least four sensing elements (214, 411) placed so as to take a direct measurement of the weight force exerted on the conveyor belt (22, 46) and said means for discharging debris comprise the unit for actuation of the rollers.

Abstract: A method for determining drilling fluid losses or gains by providing a drilling fluid, measuring a plurality of supply parameters of the drilling fluid, delivering the drilling fluid to a subsurface drilling operation, the subsurface drilling operation providing a returns drilling fluid, measuring a plurality of returns parameters of the returns drilling fluid, and determining change in composition, or loss of or gain of drilling fluid from a comparison between the supply parameters and the returns parameters.

Abstract: The invention relates to methods and apparatus for determining a downhole parameter in an underbalanced drilling environment which include: selectively activating a first fluid flowing from the formation through a wellbore while under balanced drilled; detecting the activated first fluid, and determining a depth at which said fluid enters the wellbore.

Abstract: A borehole logging system for the measure and the telemetry of properties and conditions of a well borehole environs. The system is embodied to measure fluids within the borehole, to measure high resolution images of the wall of the borehole, to transfer of data to and from equipment operating within the borehole environment, and to determine the status of equipment operating within the borehole. The embodiments are based upon emission, measurement and processing of electromagnetic radiation in the near infrared (NIR) region of the radiation spectrum.

Abstract: Embodiments of the present invention relate in general to methods and apparatus for determining downhole mud flow rates and other downhole parameters.

Abstract: A closed-loop circulating system for drilling wells has control of the flow rates in and out of the wellbore. Kicks and fluid losses are quickly controlled by adjusting the backpressure. Kick tolerance and tripping margins are eliminated by real-time determination of pore and fracture pressure. The system can incorporate a rotating BOP and can be used with underbalanced drilling.

Abstract: A closed-loop circulating system for drilling wells has control of the flow rates in and out of the wellbore. Kicks and fluid losses are quickly controlled by adjusting the backpressure. Kick tolerance and tripping margins are eliminated by real-time determination of pore and fracture pressure. The system can incorporate a rotating BOP and can be used with underbalanced drilling.

Abstract: A method for communicating with a downhole tool located in a subterranean borehole is disclosed. Exemplary embodiments of the method include encoding data and/or commands in a sequence of varying drill string rotation rates and drilling fluid flow rates. The varying rotation rates and flow rates are measured downhole and processed to decode the data and/or the commands. In one exemplary embodiment, commands in the form of relative changes to current steering tool offset and tool face settings are encoded and transmitted downhole. Such commands may then be executed, for example, to change the steering tool settings and thus the direction of drilling. Exemplary embodiments of this invention advantageously provide for quick and accurate communication with a downhole tool.

Abstract: A closed-loop circulating system for drilling wells has control of the flow rates in and out of the wellbore. Kicks and fluid losses are quickly controlled by adjusting the backpressure. Kick tolerance and tripping margins are eliminated by real-time determination of pore and fracture pressure. The system can incorporate a rotating BOP and can be used with underbalanced drilling.

Abstract: An automated method and system for recognizing a well control event includes determining a state of drilling operations. When drilling operations are in a circulating state, a benchmark for a relative flow value. The relative flow value is based on a flow of drilling fluid into a well bore and a flow of drilling fluid out of the well bore. A limit on variation of the relative flow value is determined from the benchmark. A cumulative sum for the relative flow value is determined over time in response to the relative flow value exceeding the limit. A well control event is recognized based on the cumulative sum.

Abstract: A cable system for installation on the ocean floor or under another body of water includes a plurality of sub-sea junction boxes installed at spaced locations throughout a predetermined sub-oceanic cable network. At least some of the junction boxes are located at a predetermined distance off-shore from a respective on-shore cable junction node. A single main, high fiber count conduit extends from each off-shore junction box to the respective on-shore cable junction node. Each off-shore junction box has plurality of ports for releasable connection to a selected offshore cable terminated at the junction box, and a fiber routing unit in the junction box connects at least some of the ports to fibers in the main conduit.

Abstract: This invention relates to a device for measuring the flow rate of spoil from a drilling brought to the surface by means of a drilling fluid. The device comprises means of collecting the spoil and means of continuously measuring the weight of spoil collected. The means of collecting the spoil comprise a receptacle in the shape of bucket articulated about a spindle and means of tilting the receptacle in such a way that the bucket is emptied. The measurement means comprise a measuring cell connected to the tilting means in order to measure a stress proportional to the weight of the spoil collected. The invention also relates to a method for the application of a measurement of the spoil flow rate from a drilling.

Abstract: An improved apparatus and improved method for determining the characteristics of a multi-phase fluid along a well hole having a predefined geometric profile are presented. Various state properties of the fluid, including the temperature, pressure and specific gravity are taken at the wellhead and used as starting values for calculating estimated state properties at various segments along the well hole. Once the state properties are calculated, an estimated mass flow and velocity rate for the fluid and its constituents can be calculated at specific points along the well hole by implementing computer-based programs and algorithms to extrapolate and/or iterate the known parameters and measurements in a progressively incremented manner from the locations of such given starting points at an initial segment up to other further points corresponding to a set of further sequential segments used in the geometric profile mathematical model.

Abstract: A multiphase flowmeter (30) is mounted on the piping via which a multiphase fluid flows out from a hydrocarbon well, so as to measure the flow rates of the various phases of the fluid. A back-pressure valve (34) is placed in the piping downstream from the flowmeter (30) so as to enable the pressure in the flowmeter to be adjusted, whereby the flow conditions of the fluid in the flowmeter (30) can be made compatible with the measurement domain of the flowmeter.

Abstract: A system is provided for monitoring in the real time the wellbore pit volume to promptly determine the occurrence of a wellbore kick and take corrective action to minimize fluid influx volume and/or drilling fluid losses. A system includes one or more level sensors 22 which output signals to a pit volume totalizer 20 and then to a computer 26. Computer 26 may also receive signals from one or more fluid temperature sensors 40 and one or more fluid compressibility sensors 42. The output from the computer may be displayed in real time in various monitors 28, then also may be output to a permanent record 30. Computer 36 may also automatically activate the conventional alarm 32 to alert the drilling operator to the occurrence of a kick. Substantial savings in drilling time and cost may be realized according to the present invention, along with benefits of reduced environmental contamination and enhanced well safety.

Abstract: Once an oil well has been drilled and is producing, it is desirable to monitor the rate at which oil or gas is being delivered. It is particularly useful to know when there is a change in a fluid's output rate, for that can indicate problems with the well. This monitoring is known as “production logging”. Prior to the introduction of horizontal well drilling, most wells were either vertical or only slightly deviated. However, many present-day wells have long horizontal or nearly-horizontal portions, and the techniques used to measure flow in vertical wells are not applicable to horizontal wells. Moreover, any flow rate measurement technique to be used downhole should take account not only of the several sorts of “lined” wells but also the “barefoot” ones.