Statoil Petroleum As

Equinor Energy As

Statoil Asa

Nel Hydrogen A/s

Kjetil Fjalestad

Alexey Pavlov

Dinesh Krishnamoorthy

Truls Fallet

Olav Kristiansen

Jan Høydal

Robert Aasheim

Leif Kåre Grønstad

Yilmaz Türkyilmaz

Elvira Marie Bergheim Aske

Gisle Otto Eikrem

Glenn-Ole Kaasa

Vidar Alstad

Morten Fredriksen

Petter Tøndel

Pål Kittilsen

Øyvind Kaasa

Torgeir Nakken

Elvira Marie Aske

Petter Tondel

Yilmaz Turkyilmaz

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.

Estimating flow rate at a pump

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 of the diluent in order to bring production performance closer to the optimal point, as well as a method for said optimisation.

Method and system for the optimisation of the addition of diluent to an oil well comprising a downhole pump

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 parameters.

Method for inverting oil continuous flow to water continuous flow

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.

Well control system

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.

Method and system for fluid separation with an integrated control system

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.

Control method and apparatus for well operations

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.

Method and equipment for determining the interface between two or more fluid phases

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Skien, Norway

Kjetil Fjalestad