Data processing: measuring – calibrating – or testing – Calibration or correction system – Fluid or fluid flow measurement
Reexamination Certificate
1997-06-20
2001-01-30
Hoff, Marc S. (Department: 2857)
Data processing: measuring, calibrating, or testing
Calibration or correction system
Fluid or fluid flow measurement
C702S138000
Reexamination Certificate
active
06182019
ABSTRACT:
REFERENCE TO CO-PENDING APPLICATION
Reference is made to co-pending U.S. patent application Ser. No. 08/258,262, filed Jun. 9, 1994 now U.S. Pat. No. 5,606,513 entitled DIFFERENTIAL PRESSURE MEASUREMENT ARRANGEMENT UTILIZING DUAL TRANSMITTERS, and assigned to the same assignee as the present application, and to the U.S. patent applications referenced therein.
BACKGROUND OF THE INVENTION
The present invention deals with a transmitter in the process control industry. More particularly, the present invention deals with a simplified process, used in a transmitter, for providing an output signal indicative of flow through a differential producer.
Transmitters which sense various characteristics of fluid flowing through a conduit are known. Such transmitters typically sense and measure differential pressure, line pressure (or static pressure) and temperature of the process fluid. Such transmitters are typically mounted in the field of a refinery, or other process control industry installation. The field mounted transmitters are subject to significant constraints on power consumption. Such transmitters commonly provide an output in the form of a current representative of the variable being sensed. The magnitude of the current varies between 4-20 mA as a function of the sensed process variable. Therefore, the current available to operate the transmitter is less than 4 mA.
One way in which flow computation is done in industries such as the process control industry and the petroleum industry is through the use of dedicated flow computers. Such devices either use separate pressure, differential pressure and temperature transmitters or have sensing mechanisms housed in large enclosures. These devices are generally large and consume more power than 4 mA. Additionally, they are often limited to use in specialized applications such as the monitoring of hydrocarbons for custody transfer or at wellheads to monitor the output of gas or oil wells.
Another way in which flow computation is done is through the use of local control systems, often called programmable loop controllers (PLC). PLC's typically receive inputs from separate pressure, differential pressure and temperature transmitters and compute the flow based on these inputs. Such devices are often performing additional local control tasks such as the calculation of other variables required in the control of the plant or the monitoring of process variables for alarm purposes. The calculation of flow in these devices requires programming by the user.
A third way in which flow computation is done is through the use of large computers which control entire plants, often called distributed control systems (DCS). DCS's typically perform a wide range of tasks ranging from receiving inputs from field-based transmitters to computing the intermediate process variables such as flow or level, to sending positioning signals to final control elements such as valves, to performing the monitoring and alarm functions within the plant. Because of the wide range of tasks required and the typically high cost of DCS input/output capability, memory and computational time, it is common to do a flow computation that is not compensated for all of the effects due to changing process conditions.
One common means of measuring flow rate in the process control industry is to measure the pressure drop across a fixed restriction in the pipe, often referred to as a differential producer or primary element. The general equation for calculating flow rate through a differential producer can be written as:
Q=NC
d
EY
1
d
2
{square root over (ph)} Equation 1
where
Q=Mass flow rate (mass/unit time)
N=Units conversion factor (units vary)
C
d
=Discharge coefficient (dimensionless)
E=Velocity of approach factor (dimensionless)
Y
1
=Gas expansion factor (dimensionless)
d=Bore of differential producer (length)
&rgr;=Fluid density (mass/unit volume)
h=Differential pressure (force/unit area)
Of the terms in this expression, only the units conversion factor, which is a constant, is simple to calculate. The other terms are expressed by equations that range from relatively simple to very complex. Some of the expressions contain many terms and require the raising of numbers to non-integer powers. This is a computationally intensive operation.
In addition, it is desirable to have the transmitter operate compatibly with as many types of differential producers as possible. Implementing all of the calculations and equations needed for the conventional flow equation in order to determine flow based on the output of one differential producer (much less a plurality of different types of differential producers) requires computations which can only be reasonably performed by a processor which has a high calculation speed and which is quite powerful. Operation of such a processor results in increased power consumption and memory requirements in the transmitter. This is highly undesirable given the 4 mA power constraint or conventional transmitters. Therefore, current transmitter-based microprocessors, given the above power and memory constraints, simply do not have the capability of performing the calculations in any reasonable time period.
There has been some work done in obtaining a simplified discharge coefficient equation. However, this is only one small part of the flow equation. Even assuming the discharge coefficient is extremely simplified, implementing the flow equation accurately is still very difficult given the constraints on current transmitter-based microprocessors.
Other attempts have been made to simplify the entire flow equation. However, in order to make the flow equation simple enough that it can be implemented in transmitter-based microprocessors, the simplified flow equations are simply not very accurate. For example, some such simplified flow equations do not account for the discharge coefficient. Others do not account for compressibility, or viscosity effects.
Therefore, common transmitter-based microprocessors which are powered by the 4-20 mA loop simply do not accurately calculate flow. Rather, they provide outputs indicative of differential pressure across the orifice plate, static line pressure, and temperature. These variables are provided to a flow computer in a control room as mentioned above, which, in turn, calculates flow. This is a significant processing burden on the flow computer.
SUMMARY OF THE INVENTION
A transmitter provides an output signal indicative of mass flow rate of fluid through a conduit. The transmitter includes a temperature sensor providing a temperature signal indicative of fluid temperature. A static pressure sensor provides a static pressure signal indicative of static pressure in the conduit. A differential producer provides a differential pressure signal. The transmitter also includes a controller which provides the output signal indicative of mass flow of the fluid through the conduit based on a plurality of simplified equations.
REFERENCES:
patent: 4249164 (1981-02-01), Tivy
patent: 4562744 (1986-01-01), Hall et al.
patent: 4796651 (1989-01-01), Ginn et al.
patent: 4799169 (1989-01-01), Mims
patent: 5495769 (1996-03-01), Broden et al.
patent: 5606513 (1997-02-01), Louwagie et al.
“Orifice Metering Of Natural Gas and Other Related Hydrocarbon Fluid”, Part 1, General Equations and Uncertainty Guidelines, American Gas Association, Report No. 3, American Petroleum Institute, API 14.3, Gas Processors Association, GPA 8185-90, Third Edition, Oct. 1990, A.G.A. Catalog No. XQ9017.
“Orifice Metering Of Natural Gas and Other Related Hydrocarbon Fluid”, Part 2, Specification and Installation Requirements, American Gas Association, Report No. 3, American Petroleum Institute, API 14.3, Gas Processors Association, GPA 8185-90, Third Edition, Feb. 1991, A.G.A. Catalog No. XQ9104.
“Orifice Metering Of Natural Gas and Other Related Hydrocarbon Fluid”, Part 3, Natural Gas Applications, American Gas Association, Report No. 3, American Petroleum Institute, API 14.3, Gas Proce
Hoff Marc S.
Miller Craig Steven
Rosemount Inc.
Westman Champlin & Kelly P.A.
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