Method and apparatus for measuring and controlling the flow of natural gas from gas wells

• US 5,983,164 A
• Filed: 02/25/1998
• Issued: 11/09/1999
• Est. Priority Date: 02/25/1997
• Status: Expired due to Term

• Current Assignee: Wixxi Technologies LLC
• Original Assignee: Stella LLC
• Inventors: Ocondi, Cham
• Primary Examiner(s): McElheny, Jr., Donald E.
• Application Number:
  US09/030,275
• Time in Patent Office: 622 Days
• Field of Search: 702/50, 702/55, 702/6, 702/12, 137/155, 340/856.3, 175/50, 175/48, 166/250.01, 166/250.15, 166/66, 166/66.6, 166/53, 73/152.29, 73/152.51, 73/152.52, 73/861.03
• US Class Current: 702/12
• CPC Class Codes: E21B 2200/22 Fuzzy logic, artificial intelligence, neural networks or the like
• CPC Class Codes: E21B 43/12 Methods or apparatus for controlling the flow of the obtained fluid to or in wells E21B43/25 takes precedence; valve arrangements E21B34/00
• CPC Class Codes: E21B 47/00 Survey of boreholes or wells monitoring pressure or flow of drilling fluid E21B21/08
• CPC Class Codes: G01F 1/363 with electrical or electro-mechanical indication G01F1/37 and G01F1/38 take precedence

Abstract

This system and Method serve as both a raw data logger for well operation analysis and a well event logger for well performance analysis. An improved methodology of remote event and process variable logging and data retention designed specifically to address the needs of intermittently flowing gas wells is useful for eliminating gas slippage associated with intermittent or erratic gas flow conditions, eliminating measurement errors, and lowering operating costs. The well data can be scanned in seconds for its current flow situation, and as a set of specific conditions are met, a built-in control program reacts to those conditions by shutting down the well until certain pressure criteria are met to allow the well to flow again. To maintain measurement integrity, precise event logging of the valve positions to indicate the actual flowing period are included in the flow integration. There are auto-calibration and reintegration features in the system methodology for eliminating slippage gas and eliminating settling disputes between the producer and the pipeline operator. Graphical presentation of event logs and process variable data allows the user to quickly and effectively diagnose and correct gas well problem. The same graphical presentation provides visual inspection and analysis to optimize gas well production.

Claims

1. Methods for measuring the volume and rate of gas well flow from a gas well head by electrical means to eliminate gas volume measurement errors associated with intermittent or erratic gas flow conditions in a system using a differential pressure transducer, a temperature transducer, and a static pressure line transducer all in operative communication with the gas well head, including the steps of:

providing a first electric component system having an input portion installed in operative communication with a gas well site, said component system having calibration data, gas flow parameters, and control configurations;

transmitting analog electric data as a function of time from at least the differential pressure transducer, the temperature transducer, and the static pressure line transducer to said input portion of said first electric component system;

transmitting digital electric event data as a function of time to the input portion of said first electric component system;

transmitting said analog electric data signals to a data logging manager for storage;

transmitting said digital electric event data signals to a data logging manager for storage; and

then

presenting said analog electric data and said digital electric event data from said signal for display and for analysis of well characteristics and events from said signals, including volume and rate of gas well flow from a gas well head to which it is in operative communication.

2. The methods of claim 1 wherein said analog electric data and said digital electric event data from said signals are retrievably stored for subsequent use in determining gas volume flow and analyzing data trending.

3. The methods of claim 2 wherein said stored digital electric event data is used to measure the actual gas flow period of said well for any substantially current or previous time for integration of actual gas flow at that time.

4. The methods of claim 2 wherein said stored analog electric data and digital electric event data are used for well control.

5. The methods of claim 2 wherein said stored analog electric data and digital electric event data are used to provide trending data and event logging for use in accurate gas volume flow measurement for any substantially current or previous time.

6. The methods of claim 2 wherein said stored analog electric data and digital electric event data are retrievable for subsequent use in accurately determining or analyzing data trending and gas volume flow for any substantially current or previous time.

7. The methods of claim 2 wherein said stored analog electric data and digital electric event data are used over a period of time and spliced together to form a seamless trending database.

8. The methods of claim 1 wherein a casing pressure transducer and a tubing pressure transducer in operative communication with a gas well site are also placed in analog electric signal connection with said first component system.

9. The methods of claim 2 wherein said analog electric data and said digital electric event data are retrievably stored for subsequent use in a memory archiving data management system for use in accurately determining or analyzing data tending and gas volume flow.

10. The methods of claim 1 wherein a second electric component system with calibration data, gas flow parameters, and control configurations is installed at a distance from the gas well site, and wherein said analog electric data and said digital electric event data are transmitted to said second electric component system for storage and for analysis of well characteristics and events from said signals, including volume and rate of gas well flow from a gas well head.

11. The methods of claim 10 wherein said analog electric data and said digital electric event data are transmitted to said second electric component system using data compression techniques.

12. The methods of claim 10 wherein said presentation of said analog electric data and said digital electric event data for analysis of well characteristics and events is by means of a visual display.

13. The methods of claim 12 wherein said visual display is on a monitor screen.

14. The methods of claim 10 wherein said stored analog electric data and digital electric event data at said second electric component system are used for well control.

15. The methods of claim 11 wherein said presentation of said analog electric data and said digital electric event data for analysis of well characteristics and events is by means of a visual display.

16. The methods of claim 1 wherein said system includes means for automatically calibrating some or all of the transducers as a function of the temperature in the portion of the well head where that transducer is located.