Abstract: A method for determining an estimated flow rate of fluid flow in a pump comprises: obtaining measurements of the pressure and temperature of fluid at the intake to the pump, the pressure and temperature of the fluid at the discharge from the pump, and the electrical power supplied to the pump; determining values representing either the density of the fluid and the specific heat capacity of the fluid, or the specific fluid enthalpy based on measurements and/or historical data; and calculating an estimated efficiency of the pump and an estimated flow rate of the fluid based on the measured electrical power, the measured temperatures, the measured pressures, the determined value for density and the determined value for specific heat capacity or the determined value for specific fluid enthalpy.

Abstract: A method for determining an estimated flow rate of fluid flow in a pump comprises: obtaining measurements of the pressure and temperature of fluid at the intake to the pump, the pressure and temperature of the fluid at the discharge from the pump, and the electrical power supplied to the pump; determining values representing either the density of the fluid and the specific heat capacity of the fluid, or the specific fluid enthalpy based on measurements and/or historical data; and calculating an estimated efficiency of the pump and an estimated flow rate of the fluid based on the measured electrical power, the measured temperatures, the measured pressures, the determined value for density and the determined value for specific heat capacity or the determined value for specific fluid enthalpy.

Abstract: A system for optimising injection of a diluent to one, some or all of one or more wells comprising a downhole pump and holding means for the diluent, said holding means being connected to the or each well via one or more injection lines through which the diluent may be pumped by diluent injection means, characterised in that said system comprises measurement means for real time measurement of one or more production performance parameters, and measurement of the rate of injection of the diluent; and means for optimising the injection of the diluent to at least one of said one or more wells on the basis of: (i) means for making controlled variations of the diluent injection into the at least or each well; (ii) means for the processing of the real time measurements of the production performance parameters affected by these variations to determine any necessary adjustment of the injection of the diluent towards an optimal value; and (iii) if required, making the corresponding physical adjustment of the injection

Abstract: The present invention provides a method for inverting oil continuous flow to water continuous flow and reaching one or more desired production parameters in a well producing fluid containing oil and water or inverting oil continuous flow to water continuous flow and reaching one or more desired transport parameters in a pipeline transporting fluid containing oil and water wherein there is a pump in the well or transport pipeline, comprising the following steps: (a) reducing the pump frequency until either inversion from oil continuous production to water continuous flow is achieved or a predefined stopping condition is reached; (b) if inversion has not been achieved in step (a), adjusting the wellhead pressure in the well or the pressure at the reception side of the transport line to achieve the inversion; (c) stabilising the flow at the condition reached in steps (a) or (b); and (d) carefully adjusting one or both of the wellhead pressure and pump frequency to reach the one or more desired production paramet

Abstract: A system for optimising injection of a diluent to one, some or all of one or more wells comprising a downhole pump and holding means for the diluent, said holding means being connected to the or each well via one or more injection lines through which the diluent may be pumped by diluent injection means, characterised in that said system comprises measurement means for real time measurement of one or more production performance parameters, and measurement of the rate of injection of the diluent; and means for optimising the injection of the diluent to at least one of said one or more wells on the basis of: (i) means for making controlled variations of the diluent injection into the at least or each well; (ii) means for the processing of the real time measurements of the production performance parameters affected by these variations to determine any necessary adjustment of the injection of the diluent towards an optimal value; and (iii) if required, making the corresponding physical adjustment of the injection

Abstract: A method for operating an electrical submersible pump, ESP, lifted well, the method comprising: measuring a characteristic of the well or a characteristic of a device associated with the well; generating a first control signal for instructing a change in the operation of the ESP; generating a second control signal for instructing a change in the operation of a further device associated with the well; wherein a degree of change in each of the first and second control signals is dependent on the outcome of the measuring and on a known effect caused by sending at least one of said first control signal to the ESP or said second control signal to the further device associated with the well; and sending the first control signal to the ESP and the second control signal to the further device associated with the well.

Abstract: A method for determining an estimated flow rate of fluid flow in a pump comprises: obtaining measurements of the pressure and temperature of fluid at the intake to the pump, the pressure and temperature of the fluid at the discharge from the pump, and the electrical power supplied to the pump; determining values representing either the density of the fluid and the specific heat capacity of the fluid, or the specific fluid enthalpy based on measurements and/or historical data; and calculating an estimated efficiency of the pump and an estimated flow rate of the fluid based on the measured electrical power, the measured temperatures, the specific fluid enthalpy.

Abstract: The present invention provides a method for inverting oil continuous flow to water continuous flow and reaching one or more desired production parameters in a well producing fluid containing oil and water or inverting oil continuous flow to water continuous flow and reaching one or more desired transport parameters in a pipeline transporting fluid containing oil and water wherein there is a pump in the well or transport pipeline, comprising the following steps: (a) reducing the pump frequency until either inversion from oil continuous production to water continuous flow is achieved or a predefined stopping condition is reached; (b) if inversion has not been achieved in step (a), adjusting the wellhead pressure in the well or the pressure at the reception side of the transport line to achieve the inversion; (c) stabilising the flow at the condition reached in steps (a) or (b); and (d) carefully adjusting one or both of the wellhead pressure and pump frequency to reach the one or more desired production paramet

Abstract: A system for separating an input fluid flow comprising gas and liquid into separate gas and liquid flows is provided. The system includes a primary separator configured to receive the input fluid flow and to separate the input fluid flow into a primary separator liquid output flow and a primary separator gas output flow, a first secondary inline separator connected downstream from the primary separator to polish the primary separator gas output flow, a second secondary inline separator connected downstream from the primary separator to polish the primary separator liquid output flow, a system gas outlet, a system liquid outlet, a primary separator gas output valve on the primary separator gas output flow, and a control system configured to receive measurements of liquid level within the primary separator, and identify, using the received measurements, whether a position of the primary separator gas output valve is to be changed.

Abstract: A method of controlling the annular pressure in a well during a well construction operation. The operation comprises pumping a fluid down a tubing located within the well and extracting the fluid that flows back through an annulus within said well and surrounding the tubing. The method comprises defining a set pressure pref, determining a desired extraction flow rate qc of fluid from said annulus in dependence upon the set pressure pref and a pumped flow rate into the annulus, and configuring an extraction path to achieve said desired extraction flow rate.

Abstract: A method for operating an electrical submersible pump, ESP, lifted well, the method comprising: measuring a characteristic of the well or a characteristic of a device associated with the well; generating a first control signal for instructing a change in the operation of the ESP; generating a second control signal for instructing a change in the operation of a further device associated with the well; wherein a degree of change in each of the first and second control signals is dependent on the outcome of the measuring and on a known effect caused by sending at least one of said first control signal to the ESP or said second control signal to the further device associated with the well; and sending the first control signal to the ESP and the second control signal to the further device associated with the well.

Abstract: A system for separating an input fluid flow comprising gas and liquid into separate gas and liquid flows, the system comprising: a primary inline separator configured to receive said input fluid flow and to separate said input fluid flow into a primary separator liquid output flow and a primary separator gas output flow; at least one secondary inline separator connected downstream from said primary inline separator to receive at least one of said primary separator output flows and to separate said received primary separator output flow into a secondary separator liquid output flow and a secondary separator gas output flow; a system gas outlet connected to at least one of said primary and secondary separators to output said respective gas output flow; a system liquid outlet connected to at least one of said primary and secondary separators to output said respective liquid output flow; and a control system configured to regulate flow through said primary and secondary separators to ensure a flow of gas from sai

Abstract: A method and equipment are provided for determining the level/height, of one or more interfaces between two or more fluid phases of different density that are contained in a vessel, tank or the like. The position of the different interfaces in a tank is determined by measuring the pressure thereby determining the density of the fluid over the height of the tank by using a pressure measuring rod, equipped with pressure sensors, positioned in the tank. A mathematical model or algorithm is used which calculates how the density and hence the pressure vary over the height of the tank as a function of the fluid properties of the respective fluids in the tank, the interface, on the basis of the density being the same within each layer of the respective fluid, as a respective point at which the density changes from one layer to the next in the tank.

Abstract: A method for the operation and control of gas filling from a filling station to a receiver is comprising actively controlling essential filling variables within the receiver such as temperature, pressure, and density of the gas; continuously updating estimates of the filling variables based on filling station side measurements interpreted using physical and thermodynamic relations as to make the variables available even when the receiver is not communicating with the filling station in so-called non-communication fueling; and continuously updating the estimated capacity of the receiver based on station side measurements in a non-communication fueling.

Abstract: A method of controlling the annular pressure in a well during a well construction operation. The operation comprises pumping a fluid down a tubing located within the well and extracting the fluid that flows back through an annulus within said well and surrounding the tubing. The method comprises defining a set pressure pref, determining a desired extraction flow rate qc of fluid from said annulus in dependence upon the set pressure pref and a pumped flow rate into the annulus, and configuring an extraction path to achieve said desired extraction flow rate.

Abstract: A plant for storing and supplying compressed gas comprises a storage tank (1) for gas, at least one pressurization tank (2) for gas and a buffer tank (3) for a pressure support fluid to be filled into or evacuated from lower portions of the storage and pressurization tanks. The lower portions of the storage and pressurization tanks are communicating with the buffer tank via fluid flow lines (4, 5) to fill fluid during supplying from and pressurizing gas in the plant, and a flow line (7) for evacuating fluid during refilling of the pressurization tank.

Abstract: A device for measuring rates in individual phases of a multiphase flow, such as in flow of hydrocarbon fluid through a pipe line, comprising a venturi having, seen in the flow direction thereof, a first inlet portion with deceasing cross-section, a second intermediate portion with mainly uniform cross-section, and a third outlet portion with increasing cross-section, and being situated within the pipe line. According to the present invention, the venturi is provided with a number of sensors, and the sensors are arranged in mutual distance at different cross-section areas along at least the first of the three portion of the venturi as thereby being able to determine a pressure profile along the venturi as a base for estimating rates for actual rates of the flow.

Abstract: A method and equipment are provided for determining the level/height, of one or more interfaces between two or more fluid phases of different density that are contained in a vessel, tank or the like. The position of the different interfaces in a tank is determined by measuring the pressure thereby determining the density of the fluid over the height of the tank by using a pressure measuring rod, equipped with pressure sensors, positioned in the tank. A mathematical model or algorithm is used which calculates how the density and hence the pressure vary over the height of the tank as a function of the fluid properties of the respective fluids in the tank, the interface, on the basis of the density being the same within each layer of the respective fluid, as a respective point at which the density changes from one layer to the next in the tank.