A wellhead system includes a wellhead, a fluid line extending from the wellhead, a branch line fluidly connected to the fluid line at an inlet and at an outlet, an ejector device arranged on the branch line, a tank fluidly connected by a tank fluid line to the ejector device, and a pressure control valve arranged on the branch line upstream of the ejector device. The ejector device is configured to produce a mixture that includes the fluid from the wellhead flowing in the branch fluid line with a chemical flowing the tank fluid line. The ejector device is also configured to discharge the mixture downstream of the ejector device. The pressure control valve is configured to control the flow of a fluid entering the ejector device.

A method for calibrating flow meters measuring fluid passing through a pipe wherein fluid pressures are detected and used to determine a volume or mass flow rate using an energy correlation calculation. The energy correlation calculation equates a change in potential energy for the flowing fluid with a change in kinetic energy for the flowing fluid. The energy correlation method of calculating flow rate offers lower measurement uncertainty than calculating flow by the Reynolds number versus discharge coefficient method.

A multiphase flowmeter may include a circuit including a pressure sensor configured to determine pressure data associated with a fluid mixture flowing through a chamber. The circuit may include one or more position sensors configured to determine position data associated with a position of a movable element that is configured to move within the chamber in response to pressure of the fluid mixture. The circuit may include a processor to determine a flow rate of the fluid mixture based on the pressure data and the position data and first volumes of gas and liquid within the fluid mixture based on frequency data determined from the position data. The processor may be configured to determine second volumes of water and oil within the fluid mixture based on one or more of a cut sensor or a change in an electrical parameter of the one or more position or other sensors.

A multiphase flowmeter may include a circuit including a pressure sensor configured to determine pressure data associated with a fluid mixture flowing through a chamber. The circuit may include one or more position sensors configured to determine position data associated with a position of a movable element that is configured to move within the chamber in response to pressure of the fluid mixture. The circuit may include a processor to determine a flow rate of the fluid mixture based on the pressure data and the position data and first volumes of gas and liquid within the fluid mixture based on frequency data determined from the position data. The processor may be configured to determine second volumes of water and oil within the fluid mixture based on one or more of a cut sensor or a change in an electrical parameter of the one or more position or other sensors.

Embodiments include a multiphase flowmeter system (300). The multiphase flowmeter system (300) may include a first inline flow conditioner (310) for reducing a slip velocity between a liquid phase and a gas phase of a multiphase fluid, a flowmeter for measuring a flow rate of the multiphase fluid, a second inline flow conditioner (350) for separating the liquid phase and the gas phase of the multiphase fluid, a non-radioactive sensor system for measuring one or more of a gas void fraction of the multiphase fluid and a water-cut of the multiphase fluid, and a processor (480) for computing one or more flow rates of the multiphase fluid. Embodiments further include methods of measuring one or more flow rates of a multiphase fluid and other related methods, apparatuses, devices, and systems.

A volume fraction meter that includes a flow meter coupled to a flow line. The flow line includes a turned portion and the flow meter is positioned upstream from the turned portion with respect to a flow direction. The flow meter is configured to measure a volumetric flow rate of a multiphase fluid flowing in the flow direction through the flow line. The flow line includes a nozzle opening downstream the turned portion. The volume fraction meter also includes a strain gauge coupled to the flow line between the flow meter and the turned portion of the flow line. The strain gauge is configured to measure a bending strain on the flow line upon discharge of the multiphase fluid through the nozzle opening, such that the bending strain and the volumetric flow-rate provide inputs for determining a mixture density of the multiphase fluid.

A flow metering method for an annular gas and liquid flow comprises the following steps of: first, enabling a gas and liquid mixed fluid to flow through a vertically arranged circular pipe so as to form the annular gas and liquid flow; and then measuring total flow or liquid average velocity or gas average velocity of the gas and liquid mixed fluid; measuring physical quantities, such as temperature, pressure, gas fraction and the like, of the gas and liquid mixed fluid; and finally, accurately figuring out liquid volume flow and gas volume flow according to analysis of a gas and liquid slip factor.

A flow metering method for an annular gas and liquid flow comprises the following steps of: first, enabling a gas and liquid mixed fluid to flow through a vertically arranged circular pipe so as to form the annular gas and liquid flow; and then measuring total flow or liquid average velocity or gas average velocity of the gas and liquid mixed fluid; measuring physical quantities, such as temperature, pressure, gas fraction and the like, of the gas and liquid mixed fluid; and finally, accurately figuring out liquid volume flow and gas volume flow according to analysis of a gas and liquid slip factor.

A drilling system used with drilling fluid for drilling a wellbore has at least one choke in adjustable communication with flow from the wellbore. A programmable control device determines a flow coefficient value of the choke from a measured position value and a stored characteristic of the choke. The device then calculates a first value of the flow of the drilling fluid from the wellbore through the choke based on the flow coefficient value and a pressure differential measured across the choke. The device adjusts operation of the drilling system at least partially based on the calculated flow value. To adjust operation, the device can set the choke (or another choke) to a set flow value relative to the calculated first flow value. Density of the flow can also be determined so the device can adjust operation based on mass flow rate.

A subsea equipment assembly includes a first component having an axis, a second component, and an anti-vibration bracket. The anti-vibration bracket is attached to the first component and the second component. In use the first component is caused to vibrate at least in a radial direction relative to the axis. The anti-vibration bracket includes a plate portion. The plate portion extends at least radially away from the first component and includes an attachment region located a radial distance away from the first component, the second component is attached to the attachment region. The anti-vibration bracket includes an array of slots, at least some of the slots of the array of slots are located between the first component and the attachment region.