Atlantic Richfield Company

Miroslav M Kolpak

Richard L Payne

Jean S Weingarten

M Jane Williamson

Steven G Petermann

Sophany Thach

Richard F Stoisits

Tuan D Ma

Terry J Rock

Jeffry A Rugen

S Michel Bucaram

Gordon J Krist

Michael C Vincent

Scott A Mattison

Gary K Youngren

William D Hetherington

Anthony C Schwarz

James C Wilcoxson

Ronald G Oba

Hydrocarbon fluid production wells and similar process flowstreams have a spiral baffle-type separator interposed in a surface flowline for separating fluids of different densities, such as gas from oil or gas from oil and from water, for example. Particulate solids may also be separated from the fluid flowstream. The separator includes a spiral baffle of single or multiple diameters interposed in an elongated cylindrical casing connected at its opposite ends to suitable fittings whereby the separator may be connected to conventional fluid flowlines on the surface just downstream of a wellhead or otherwise in a process flowstream. Multiple spiral baffle separators may be connected in series to provide multiple stages for separation of fluids of different densities. The separator is particularly compact, mechanically uncomplicated and may be easily adapted to be interposed in well production fluid flowlines or conduits for process flowstreams.

Separator systems for well production fluids

A method for mitigating slugs in pipelines carrying multiphase mixtures of gas and liquid by adding a quantity of a surfactant selected from the group consisting of ethoxylated alcohols, polyglycosides and alpha olefin sulfonates to the multiphase mixture in the pipeline. After addition of a quantity of surfactant, a determination is made as to whether the quantity of surfactant added is sufficient to mitigate the slugs, and thereafter adjusting the quantity of surfactant added to an amount sufficient to mitigate the slugs.

Method for mitigating slugs in a pipeline

Multiphase fluid flowstreams of gas, oil and water are measured by flowmeters which include an embodiment using a turbine flowmeter and a densitometer with total accuracy in the range of .+-.15%, and an embodiment using a gas-liquid separator and a Coriolis flowmeter for flowstreams of a relatively high gas-to-liquid ratio with accuracies of .+-.5% when the gas carry-over in the liquid flowstream is less than about 5%. A second alternate embodiment includes a water fraction meter, a turbine flowmeter and a densitometer for measuring flows with relatively low gas-to-liquid ratios but accurate measure of the water fraction. A meter capable of handling relatively high gas-to-liquid ratio but with residual gas in the liquid flowstream of less than 5% includes a separator, a Coriolis meter for measuring the liquid density and mass flow rate in the liquid flowstream and a densitometer and turbine flowmeter for measuring the fluid in the gas flowstream leaving the separator. A fourth alternate embodiment includes a turbine flowmeter and a densitometer in both flowstreams leaving the separator and a water fraction meter in the liquid flowstream wherein mixtures with high gas-to-liquid ratio and residual gas in the liquid flowstream of up to about 20% may be measured.

Systems and methods for measuring flow rates and densities of the

A gas-liquid separator system having a control system for controlling and maintaining a 'normal' liquid level in the separator vessel. The system is capable of operating without the need for external power (e.g. electric, etc.) or the need for process gas to operate the valves. Also, the system is 'fail safe' since the control valves for both the gas and liquid from the vessel will be in an open position if the control system fails. The system has control valve units on both the liquid and the gas outlets of the vessel. Each control valve unit is basically similar in constructon and has a valve element moveable between an open and a closed position by changes in differential pressure across a diaphram. The valve units are connected to the vessel and to each other to sense and response to any changes in the differential pressure between the top and the bottom of the vessel to open or close the respective valves to maintain or to reattain the normal level in the vessel.

Level control system for gas-liquid separators

Multiphase fluid flowstreams may be analyzed to determine to gas fraction of the fluid by defining a zone in a conduit in which the fluid flowstream is caused to vibrate either laterally or longitudinally at a resonant frequency of vibration of the fluid flowstream using a transducer or by causing the fluid to flow through an orifice in the conduit. A vibrating zone within the conduit is delimited by spaced apart ports in the conduit and/or spaced apart grilles which reflect the longitudinal vibrations. Lateral vibrations may be enhanced by causing the flowstream to flow through a rectangular passage in the conduit. Spectral analysis of the vibrating flowstream identifies the resonant frequency of vibration which, together with pressure and temperature measurements may be used in calculating the gas fraction.

Measuring vibration of a fluid stream to determine gas fraction

A gas-liquid separator for a well pump includes a stationary helical baffle disposed in a tubular housing for separating gas from liquid and conducting gas through a center conduit disposed in the housing to a tubing string in communication with the separator or into the well annulus for flow to the surface. The baffle may be interposed in a conventional downhole submersible pump between the motor section and the pump section and the pump section may be modified to have a hollow impeller drive shaft for conducting gas separated by the separator through the pump section and out of gas discharge ports in the pump section housing. In an alternate embodiment gas is discharged from the hollow drive shaft into the tubing string and liquid separated from the gas is pumped through the pump section and out into the wellbore annulus. The baffle may have at least two stages, one of which causes some of the liquid being conducted through the separator to bypass the second separator stage and flow directly to the pump inlet so that more effective separation of gas from liquid occurs in the second stage and all of the liquid entering the pump inlet has minimal gas content.

Gas-liquid separator for well pumps

Multiphase fluid flow, such as gas and water, is controlled to provide splitting the flow from a supply conduit into one or more branch conduits with a predetermined gas-to-liquid ratio in the branch conduits by providing a flow mixing device interposed in the main conduit at the intersection of the main conduit with the branch conduits and a variable area orifice provided by a sleeve type closure member to effectively regulate the gas-to-liquid ratio entering the branch conduit. Gas to liquid ratios may be varied by providing the branch conduits as swivel connections to the main conduit so that the entry portion of the branch conduit may be oriented vertically upward or downward or at a selected position in between. Gas-to-liquid ratios may be measured by flowmeters and differential pressure gauges located upstream and downstream of the intersections of the branch conduits with the main supply conduit or manifold.

Multiphase fluid flow splitting and measurement

A downhole gas-liquid separator for multiphase fluid producing wells includes a tubular member with a spiral baffle disposed therein and a duct including an inlet disposed adjacent the discharge end of the spiral baffle. Fluid flow into the separator undergoes substantial gas and liquid separation by centrifugal forces imposed on the liquid as it progresses through the spiral flowpath. Gas is drawn off at the discharge end of the spiral baffle and discharged into the wellbore annulus while liquid and a small amount of gas pass on through the separator and the production tubing to the surface. The spiral baffle may be disposed in the wellbore between the distal end of the production tubing string and the point of entry of gas and liquid into the wellbore. The separator may include a retrievable tubular body inserted in a ported nipple interposed in the tubing string.

Downhole gas-liquid separator for wells

Natural gas is reinjected into an earth formation for storage and/or stimulating the recovery of hydrocarbon liquids by mixing the gas with water at a pressure sufficient to maintain bubble flow of gas dispersed in a water flowstream in a range of volumetric gas fraction up to about twenty percent of total flow. A water and gas distribution system includes static flow mixers for maintaining uniform distribution of gas bubbles in the water flow stream through the distribution conduits. The mixers may comprise multi-stage bladed mixing elements of the same or opposite pitch and extending across the intersection of branch conduits with the main conduit of the distribution system. The water and gas may be mixed in an injection well having a tubing string extending within the well and having a distal end below the point of injection into an earth formation so that a uniform gas and water mixture enters the formation through the well perforations.

Simultaneous water and gas injection into earth formations

Multiphase fluid flow, such as a mixture of oil, water and gas, is measured by a system which includes one or two densitometers for measuring the multiphase fluid density flowing through a flowline or conduit and a flow restriction, pump, expander or heat exchanger interposed in the flowline between the densitometers to effect a pressure or temperature change in the multiphase fluid. Densities, pressures and temperatures are measured on the upstream and/or downstream sides of the flow restriction, pump, expander or heat exchanger and the measured values of density, pressure and temperature are used to obtain the flow rates of the respective phases in the flowstream.

Multiphase fluid flow measurement

The liquid and gas volumetric flow rates of a multiphase fluid mixture are measured by pumping the fluid mixture with a positive displacement pump such as a multi-helical lobed rotor type pump, measuring the pressure differential, temperature differential and power input to the pump and calculating the liquid volumetric flow rate and gas volumetric flow rate based on the measured parameters, pump coefficients for friction horse power, fluid leakage and heat transfer, together with predetermined values of liquid and gas specific heat, density and polytropic compression exponent. Approximate flow rates of gas and liquid may be determined by monitoring the pump power input and fluid pressure and temperature changes across the pump with sufficient accuracy for applications such as in pumping crude oil and natural gas mixtures from production wells.

A slug flow mitigation and gas separation device for well production fluids includes a primary fluid inlet conduit and a slug mitigation and gas separation chamber formed by a conduit section mounted generally vertically above the primary conduit. Spaced apart branch conduits interconnect the primary conduit with the slug mitigation and separation chamber and a check valve is interposed in the branch conduit disposed in the downstream direction of fluid flow through the device. Gas vent conduits are in communication with the slug mitigation and separation chamber for conducting separated gas away from the device.

Fluid slug flow mitigation and gas separation system

Multiphase (gas and two liquid phases) fluid flowstreams are measured to determine the total flow rate, fluid density, the fraction of gas, and one liquid in the total liquid mixture by passing the flowstream through a volumetric or mass flow meter (16, 40), a densimeter (12) and a meter (14) which measures the fraction of one liquid in the two liquid mixture. The total fluid flow rate may be measured by a single tube flow meter (40) having adjacent loops which provide tube legs (49, 51) positioned adjacent each other and vibrated laterally at a predetermined frequency and amplitude while measuring pressures in the contraflowing streams in the adjacent tube legs. The density and gas fraction of the flowstream may be determined by vibrating a tube containing the flowstream over a range of frequencies and measuring the phase angle and amplitude of the fluctuating fluid pressures compared with acceleration of the tube to determine the sloshing natural frequency of the fluid mixture. The tube may be vibrated at a frequency far from the sloshing natural frequency of the fluid mixture to determine the fluid density.

Multi-phase fluid flow mesurement

Systems for determining the gas compression exponent, k, and the compressibility factor, Z, include a chamber which may be reduced in volume while the pressure, temperature and volume changes are recorded. The system for determining compressibility factor includes a temperature controller and heat exchanger which varies the temperature in the chamber after a compression process or while holding the volume of the chamber constant during multiple temperature changes. Values of pressure, temperature and volume are measured at all conditions. The compression exponent is measured by extrapolating a curve of pressure versus time while allowing the temperature of the gas to decay from heat exchange with the structure forming the chamber. The compressibility factor is determined by comparing the ratios of compressibility factors at three separate conditions of pressure, volume and temperature using an iterative technique based on an equation which utilizes a curve fitted form of the Standing Katz diagram having variables which include a pseudo-reduced temperature.

Measurement of gas properties

Multiphase (gas and two liquid phases) fluid flowstreams are measured to determine the total flow rate, fluid density, the fraction of gas, and one liquid in the total liquid mixture by passing the flowstream through a Ceriolis flow meter (16, 40), a densimeter (12) and a meter (14) which measures the fraction of one liquid in the two liquid mixture. The total fluid flow rate may be measured by a single tube flow meter (40) having adjacent loops which provide tube legs (49, 51) positioned adjacent each other and vibrated laterally at a predetermined frequency and amplitude while measuring pressures in the contraflowing streams in the adjacent tube legs. The density and gas fraction of the flowstream may be determined by vibrating a tube containing the flowstream over a range of frequencies and measuring the phase angle and amplitude of the fluctuating fluid pressures compared with acceleration of the tube to determine the sloshing natural frequency of the fluid mixture. The tube may be vibrated at a frequency far from the sloshing natural frequency of the fluid mixture to determine the fluid density.

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Plano, TX, United States of America

Miroslav M Kolpak