US 2008/0300802 A1Published application

Method of measuring gas flow

Assigneezed.i solutions Inc.

InventorsIqbal Lakhani, Tokunosuke Ito, Brian Zerb, Long Zhao, Robert Do

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Abstract

A method of measuring a dry gas flow from hydrocarbon wells. The hydrocarbon wells produce a stream which contains liquids and natural gas. The method comprises providing a differential flow measurement device (orifice) located at a well site containing the hydrocarbon wells. The method further includes testing the stream for gas composition and physical characteristics. Additionally, the method comprises measuring a static temperature (T) of the stream, measuring a static pressure (Ps), and measuring a pressure differential (dP) in the differential flow measurement device (orifice). The method includes computing the liquid-gas ratio (LGR) of the stream, computing the wet gas flow rate (Qw) of the stream, computing a first dry gas flow rate (Qd1) and a second dry gas flow rate and utilizing a iterative process to correct and obtain the dry gas flow rate. The data may be transmitted to another location.

Claims22

Dependent claims

A method of measuring a dry gas flow from hydrocarbon wells, said hydrocarbon wells producing liquids and natural gas so that a stream is produced, the method comprising:

providing an orifice device, said orifice device having an elliptical throat, and wherein said orifice device is located at a well site containing the hydrocarbon wells;
testing the stream for gas composition and physical characteristics;
measuring a flowing temperature of the hydrocarbon stream;
measuring a flowing pressure;
measuring a pressure differential in said orifice device;
computing the liquid to gas ratio (LGR) of the stream;
computing the wet gas flow rate of the stream;
computing a first dry gas flow rate utilizing a first model means, the first model means includes the following computation:
wet flow rate/dry flow rate=Qwet/Qdry=(term 1)×(term 2)×(term 3)+(term 4)+(term 5);
wherein term 1 is a correlation for volumetric flow rate of the fluid in terms of mass;
wherein term 2 is a correlation for the differential pressure;
wherein term 3 is a correlation for the static pressure;
wherein term 4 is a correlation for the beta ratio of the flow meter;
wherein term 5 is a correlation for the beta ratio of the flow meter;
computing a second dry gas flow rate utilizing a graphical representation of a second model means;
correcting the first dry gas flow rate and the second dry gas flow rate in order to obtain the derived dry gas flow rate.

13 more elements

A method of metering natural gas without separation of liquids in a stream, said stream containing the natural gas and liquids from hydrocarbon wells, the method comprising:

estimating physical parameters of the stream;
measuring the following parameters of the stream:
wet gas flow (Qw), flowing pressure (Pf), differential pressure (dP), liquid to gas ratio (LGR) and temperature (T);
computing a first dry gas flow (Qd1) utilizing a first model means as follows:
wet flow rate/dry flow rate=Qwet/Qdry=(term 1)×(term 2)×(term 3)+(term 4)+(term 5);
wherein term 1 is a correlation for volumetric flow rate of the fluid in terms of mass;
wherein term 2 is a correlation for the differential pressure;
wherein term 3 is a correlation for the static pressure;
wherein term 4 is a correlation for the beta ratio of the flow meter;
wherein term 5 is a correlation for the beta ratio of the flow meter;
computing a graphical representation of Qw/Qd, LGR and dP utilizing the second model means;
obtaining a second dry gas flow (Qd2) from the graphical representation of the second model means;
correcting the first dry gas flow rate (Qd1) and the second dry gas flow rate (Qd2) in order to obtain the derived dry gas flow rate Qdd.

10 more elements

A method of metering natural gas without separation of liquids from a stream, said stream containing natural gas and liquids from hydrocarbon wells, the method comprising:

flowing the stream through an orifice device having an elliptical throat;
estimating the density of the natural gas and fluid components of the stream;
estimating physical parameters of the stream;
measuring the following parameters:
wet gas flow (Qw), flowing pressure (Pf), differential pressure (dP), liquid to gas ratio (LGR) and flowing temperature (T);
computing a first dry gas flow (Qd1) utilizing a first model means;
computing a graphical representation of Qw/Qd, LGR and dP utilizing a second model means;
obtaining a second dry gas flow (Qd2) from the graphical representation of the second model means;
correcting the first dry gas flow rate (Qd1) and the second dry gas flow rate (Qd2) in order to obtain a derived dry gas flow rate (Qdd).

6 more elements

Dependencies are inferred from the claim text.

Facts

Application: 11/895,359Filed 24 Aug 2007
Priority: 30 May 2007
Published: 4 Dec 2008
Term ends: Not estimatedThe source records don’t support an estimate.

Classification4 codes

G01F 1/44
Details of construction of the flow constriction devices: venturi tubes
G01F 1/74
Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow: devices…
G01F 15/02
Details of, or accessories for, apparatus of groups G01F1/00 - G01F13/00 insofar as such details or appliances are not adapted to particular…
G01F
Measuring volume, volume flow, mass flow or liquid level

Family

Application11/807,815Continuation in part · filed 30 May 2007
Application11/895,359Continuation in part
US 2008/0300792 A1Published application
US 7,623,975 B2Related patent
US 7,653,489 B2Related patent
US 2008/0300802 A1This patent

From the US filing history. Foreign family members aren’t listed.