CA2320875C

CA2320875C - Method for measuring and controlling the flow of natural gas from gas wells

Info

Publication number: CA2320875C
Application number: CA002320875A
Authority: CA
Inventors: Cham Ocondi
Original assignee: CH2M Hill Inc
Current assignee: Wixxi Technologies LLC
Priority date: 1998-02-25
Filing date: 1999-02-25
Publication date: 2008-11-25
Anticipated expiration: 2019-02-25
Also published as: EP1060450A4; CA2320875A1; JP2002505435A; WO1999044168A1; EP1060450A1; US5983164A

Abstract

This method serves as both a raw data logger (36) 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 (1.1, 34) 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 (1.2) of the valve positions to indicate the actual flowing period are included in the flow integration.

Description

MBI'HOD FOR MEASURING AND CONI'ROI.LING TI>E FLOW OF NATURAL GAS

2 FROM GAS WELLS

3

4 RELATED U.S. APPLICATION DATA:

7 This application relates to U.S. Provisional Application Ser. No.
60/039,125, filed Feb. 25, g 1997, for IREC METHODOLOGY, now United States Patent 5,983,164, issued November 9,1999, 9 entitled "Method and apparatus for measuring and controlling the flow of natural gas from gas wells".

12 Field of the Invention 13 This invention relates to systems and methods for measuring volume and rate of gas well 14 flow by electrical means using differential pressure with time integration.
More speciflcally it relates to an improved methodology for resolving me,asurement slippage associated with intermittent or 16 erratic flow conditions in order to enhance accurate gas well flow measurement. In addition it relates 17 to a method for improving gas flow control, and conconritant to that, optimum gas reservoir recovery.

19 Descrintion of the Related Ar4 Because the majority of gas wells are in a decline stage, and therefore flow intermittently, the 21 conventional mechanical chart recording and electronic flow measurement inventions are inaccurate.
22 The gas industry aclwowledges that as much as 20 percent of natural gas production is not acoounted 23 for, and therefore not paid for, because of the inadequacies of the existing measurement systems.
24 These inadequacies are primarily due to the fact that the majority of gas wells flow intermittently, while existing flow measuring neechanical circular chart recording and electric computer systems are 26 designed to measure continuous flow. Currently, these mistakes cannot be corrected because the 27 existing measurement systems do not provide raw data for an audit trail for use in recalculating 28 possible errors due to interpretations nor do they in any other way reproduce the actual flow results.
29 Furthermore, in both of the state-of-the-art measvrement systems, the recorded data which is available can be manipulated by either the gas producers or the gas purchasers in their favor. As is farther 31 detailed below, these measurement errors and the inability to fairly and retiably audit or correct them, 32 are the main cause of disputes between gas producers and gas purchasers. In addition, the lack of 33 audit-trail or analyticai quality gas flow trending data which could provide historical profiles of gas 34 reservoir and gas flow performance for each well prevents the gas producer from achieving effective control and optimization of the gas well. The lack of analytical quality trending data leads to faulty 36 gas production practices, and as a result, most gas well resecvoirs are poorly managed, and fail to 37 allow for well production optimization.
38 The most commonly used gas flow measurement system is the mechanical multi-pen chart 39 recorder system. It adequately meets the gas industry's flow measurement needs for accounting 1 purposes if the well flows at a stable, constant rate. However, this situation is rare, due for example, 2 to intenmittent gas flow, line surging, and mechanical vibration at the chart, each of which can cause 3 a solid band of ink on the chart, thereby obscuring the actual gas flow, and resulting in gas flow 4 measurement slippage, i.e. improperly measured gas flow. Even in the absence of those conditions, the thickness of the ink track on the chart may cause errors of as much as 30 minutes. Furthermore, 6 because of their lack of adequate detail, and because each person who integrates a chart will do it 7 differently, since no raw data is available, circular charts are incapable of providing a reliable audit-8 trail. These and other short comings make chart recorders inadequate to provide accurate gas flow 9 data, especially for wells with erratic gas flow, plus they provide no well control options.
With the recent advancements of computer technology, electronic flow measurement (EFM) 11 systems which are capable of frequent sampling and flow integration have begun to be used to replace 12 the circular chart and mechanical flow integration systems. However, the on-site EFM systems 13 introduce different problems that may result in gas flow measurement slippage. First, it must be 14 understood that EFM systems calculate gas flow based on data generated by transducers that convert line pressure, differential pressure and the temperature of the gas flow into electrical signals of about 16 1 to about 5 volts. These three variables are then converted to engineering numbers and are the basic 17 gas flow variables used to determine gas flow volume using the industry wide accepted formula of the 18 American Gas Association (AGA-3). These basic variables which are used in EFM systems at an on-19 site, i.e., remote, calculating computer provide some improvement in overall accuracy and timeliness of gas flow measurement, as compared to mechanical multi-pen chart recorder systems, but they 21 create a new set of problems in accurately measuring intermittent gas flow.
These problems include 22 the total reliance on the signal from the differential transducer to determine the flow/no-flow 23 condition of the well for gas pressure, because 0 inches differential pressure does not necessarily mean 24 that there is "zero" or "no gas flow" without actual knowledge or determination of actual gas flow.
Without going into excessive details herein, an EFM system calculates and accumulates an hourly 26 average flow volume so long as both the line pressure and differential pressure are positive. In 27 addition, for the EFM system to be accurate in flow integration of erratic or intermittent flow, the 28 transducer must be unconditionally infailible, and the gas flow in an ideal condition of no turbulence.
29 This ideal condition does not exist in nature, because, as the gas flow rate approaches or falls below a predetermined level, say 10 inches (of water pressure) of differential pressure, the relationship 31 between the differential pressure and the actual flow becomes erratic. At that point, these systems are 32 not reliable because they rely on a preset moving differential pressure zero (zero cut-off) reference to 33 establish the integration or flow period. For reasons set forth in the accompanying STELATm 34 METHODOLOGY brochure, the accuracy of the typical EFM transducer can be in error by about 0.25% because of total accuracy and transducer drift. Typically, an EFM system sets the calibration of 36 the transducer at, say exactly 1 volt for 0 inches of differential pressure, and the transducer reading 37 can be in error by as much as say about 0.5 inches. Since the flow calculation is reliant on a 38 differential pressure reading to establish a flow condition, this error causes problems. As a result, the 1 gas flow could be shut off, while the EFM system continues to compute about 50,000 cubic feet of gas 2 per day, and conversely, the flow could actually be 50,000 cubic feet per day, yet the transducer might 3 indicate 0 inches of differential pressare, with the result that the EFM
system would calculate no flow.
4 Furthermore, the curr+ent, but misguided, logic says that the accuracy of the flow computing system is based on the accuracy of the EFM flow transducers which measure line pressure, differential 6 pressure, and temperature and the frequency and speed of the calculations.
However, accuracy really 7 depends on precise awareness of the integration period, that is, knowing when true flow/no-flow 8 conditions occur and knowing the true differential pressure based on a dynamically adjusted true zero.
9 Currently, it is a common practice of the pipeline operator to assume that the no-flow point must be established at a certain positive differential pressure value, which incidentally ensures that any 11 slippage is in favor of the purchaser. However, the imposition of such a zero cut-off prematurely cuts 12 off flow calculation while the well is still flowing. This is the major cause of ineasurement slippage in 13 EFM systems. Under other conditions, the zero base flow could also shift positively, and without a 14 zero cut-off, show a difference of 20%.
The EFM systems convert all engineering values of flow variables, calculate, and store hourly flow 16 volumes at the well head location, which is usually remote from the central operations office.
17 Typically the raw data of the basic flow parameters are discarded during integration, thereby 18 eliminating the audit trail capability of this system. Consequently, the raw data needed for 19 reintegration is unavailable. As a result, recalculation of the local hourly averaged data will not match the average of the integrated flow result because of the square-root effect in the flow formula of 21 the American Gas Association (AGA-3). That is, the sum of the square-root will equal the square 22 root of the sum only ff the line pressure and differential pressure remain constant, but in nature these 23 pressures are not constant in most wells. This lack of audit trail requires the field personnel to enter 24 all of the calibration factors and all data needed for the AGA-3 flow calculation before activation of the on-site EFM systems. This information along with the transducer readings allows the on-site 26 computer to calculate flow. The result is an average hourly flow, even if the well was only open 30 27 minutes, that cannot be recalculated because the raw data has not been stored. Erroneous integrated 28 results due to incorrect entry of the above data, are found to be very difficult to correct.
29 Not only is unintentional human enror likely with the EFM systems, but, as set forth in the accompanying STELAT'"' METHODOLOGY brochure, the possibility of intentional manipulation 31 exists. The hourly managed data provided by the EFM system further obscures the analytical qualiry 32 data needed by the producer to operate and manage the production of the well.

It is thus an object of the present invention to provide a method and system which is 36 specifically designed to solve the gas flow measurement and control problems of the prior art chart 37 and EFM systems.
38 It is another object of the present invention to provide to meet the two main objectives for gas 1 well flow measurement and control of providing analytical quality data and event logs for production 2 optimization, also to provide analytical quality data and event logs for accurate gas flow integration 3 with complete audit-trail, and to leave gas well operational control to the field personnel and keep the 4 accounting procedures in a central office.
The present invention specifically overcomes the disadvantages in the prior art discussed 6 above. The method in accordance with the present invention basically includes at least a "remote 7 component system" and a "host component system". The remote component system is located at the 8 well head location, and is usually remote from the central operations office at which the host 9 component system is located. The remote component system basically includes some form of electronic computer data logger, such as an electronic chart recording system.
The electronic data 11 logger of the remote component system is connected to transducers which measure and transmit line 12 pressure, flow differential pressure, and temperature, all as analog data.
In preferred embodiments, 13 the remote component system is also connected to transducers which measure and transmit the gas 14 well casing pressure and the pressure of the tubing immediately adjacent to the well head, also as analog data. The remote component system electronic data logger includes software to trend the 16 analog data accurately, and a memory system to store in a retrievable format, as a function of time, the 17 analog data so collected. To maintain measurement integrity the memory system also stores and logs 18 digital data of precise events, such as valve positions, to indicate the actual period of gas flow, all as a 19 function of time. The remote component system also includes a mechanism for transmitting, using a data compression technique, both analog trending and event log digital data to the host component 21 system, which is normally located at the central operations office, upon request.
22 The system and method of the present invention is designed to specifically address the needs 23 of the intermittently flowing well. It has no time span limitations. The well can be scanned from the 24 host component system location in seconds for its current flow parameters, and, as a set of specific conditions are met, a control program can be caused to react to those conditions, for example under 26 conditions of low flow pressure, by shutting down the well until certain pressure criteria are met, and 27 then allowing the well to flow again. A computer program assists in the calibration of the sensors that 28 monitor the vital temperatures and pressures of the well, thereby also minimizing maintenance cost.
29 The auto-calibration and reintegration features in the system of the present invention methodology eliminate the problems due to the failure to accurately measure slippage gas, and can thereby either 31 eliminate or provide data for use in settling disputes as to gas volume between the gas producer and 32 the pipeline operator. The host software can also be loaded into a notebook computer and allows the 33 user the portability of using the system in the field.
34 These and other objects of the present invention will become apparent to those skilled in the art from the following detailed description and accompanying drawings, showing the contemplated 36 novel construction, combination, and elements as herein described, and more particularly defined by 37 the appended claims, it being understood that changes in the precise embodiments to the herein 38 disclosed invention are meant to be included as coming within the scope of the claims, except insofar 1 as they may be precluded by the prior art.

4 The accompanying drawings which are incorporated in and form a part of this specification

5 illustrate complete preferred embodiments of the present invention according to the best modes

6 presently devised for the practical application of the principles thereof, and in which:

7 FIG. 1 is a schematic representation of gas well head incorporating transducer elements of

8 the remote component system.

9 FIG. 2 is a simplified flow-chart of the remote component system of the present invention.
FIG. 3 is a simplified flow-chart of the host component system of the present invention.
11 FIG. 4 is an example of the system of the present invention Trend screen.
12 FIG. 5 is a flow-chart of an alternative embodiment of the remote component system of the 13 present invention.
14 FIG. 6 is a flow-chart of an alternative embodiment of the host component system of the present invention.

18 For the purposes of promoting an understanding of the principles of the present invention, 19 reference will now be made to the embodiments and alternatives illustrated in the drawings, and specific language will be used to describe the same. It will nevertheless be understood that no 21 limitation of the scope of the present invention is thereby intended. The embodiments illustrated and 22 explained are exemplary only. Like reference numerals are used to designate similar structures in the 23 views of the various figures. Alterations and modifications of the illustrated apparatus and methods, 24 and such further applications of the principles of the present invention as illustrated therein being contemplated as would normally occur to one skilled in the art to which the present invention relates 26 are intended to be within the scope of the present invention.
27 Referring first to FIG. 1, a schematic representation of gas well head, generally 10, 28 incorporating various transducer elements of the remote component system, and from which the 29 typical blow down and separator elements have been removed for simplicity of exposition. Various pressure and temperature data is shown for representative purposes only. When the well is closed by 31 valve 12, plunger 14 is normally at the bottom of the well tubing, not shown, but when valve 12 is 32 opened, plunger 14 rises through the well tubing to the plunger arrival location 16 to push water, salt 33 water, hydrocarbons and mixtures thereof from the tubing for disposal at blow down and separator 34 elements, not shown. Gas can then flow through tubing 18 through to orifice 20 to provide a differential pressure reading at transducer 22, in the manner which is well known in the art.
36 Downstream of orifice 20 are standard temperature transducer 24 and standard static line transducer 37 26. In addition, a casing pressure transducer 28 is connected to the well head at the top of the casing, 38 not shown, and tubing pressure transducer 30 is located downstream of well head 10, but upstream of 1 orifice 20.
2 Now referring to the simplified flow-chart of FIG. 2, the operation of the remote component 3 system, generally 32, of the present invention will be explained. Analog and digital data is 4 transmitted from transducers 22 (differential pressare reading), 24 (temperature transducer), 26 (static line transducer), 28 (casing pressure transducer) and 30 (tubing pressnre transducer) are electrically 6 connected to input device 34, and thence transmitted to data logging manager 36 for storage on any 7 media, and for farther transmission to memory archiving data compression and data management 8 system 38. The compressed data is then transmitted to the host component system, generally 40, see 9 FIG. 3. Transmission may be by remote telemetry system 42, as shown, or by direct wiring, which is normally not practical in view of the vast distance between the gas wells and the central operations 11 office. Remote telemetry system 42 may most efficiently operate by means of a wireless or 12 conventional phone line system, although other state-of-the-art transmission means, such as satellite 13 transmission, may be used.
14 In preferred embodiments the data management system 38 can be programmed to activate control modules 44 to activate control outputs 46 to, for example, open and close valves in real time to 16 optimize well output. The activation of control module 44 and control output 46 may be remotely 17 controlled by telemetry from host component system 40.
18 Referring again to flow-chart FIG. 2, the remote component system of the present invention 19 will continue to scan and save all active analog data received from transducers 22, 24, 26, 28 and 30 at a preset interval. As explained above, the data will be compressed and stored both in short term 21 memory archiving data compression and data management system 38, for say about a one month 22 duration, and optionally, in preferred embodiments, in a mass storage system 48, using state-of-the-art 23 storage devices may be used to store data from the remote component system for the life of the well.
24 One such preferred mass storage device is a PCMCIA card with up to 100 MB
capacity or about 50 years of data storage. Event logs of digital status changes or soRware status changes will be time 26 stamped and stored in Event log files. Referring now to flow-chart FIG. 3, the host component 27 system of the present invention includes a telemetry driver 48 for receiving data from and sending 28 data to telemetry driver 42. this data is then processed through memory archiving data compression 29 AGA-3 flow calculation processor 50 from which it can be evaluated, for example in preferred embodiments by displaying it as a graphic display on graphic display user interface report generation 31 monitor/input device 52. A representative example of the trend screen of the system of the present 32 invention is shown in FIG. 4, and is discussed in additional detail below.
As explained above, the 33 data will be stored both in short term memory in module 50, again for say about a one month 34 duration, and optionally, in preferred embodiments, in a host mass storage system 54, again using state-of-the-art storage devices.
36 In preferred embodiments, the system of the present invention host component system 40 37 includes a computer, say a personal computer running, for example Windows software, say versions 38 3.1 and higher, capable of uploading data from the system of the present invention remote component 1 system 32, as well as downloading control strategies back to the remote component system 32, again 2 by means of a wireless or conventional phone line system, for example.
Specifically designed 3 computer software, a sample of which is submitted with this application, allows the host component 4 system to splice the trending data seamlessly for the life of the well. The latest versions of AGA-3 and AGA-8 may be loaded along with software to handle flow calculation to determine gas flow 6 volume. This provides an effective way to recalculate the gas volume for any time period using 7 modified parameters or scaling factors, thereby providing a means which can be used to settle volume 8 disputes between producers and pipeline operators. The system of the present invention host 9 component system is essentially an electronic chart integrator with no retracing or human intervention required, thereby having high reproducability, and no opportunity for human error. The raw database 11 is maintained as a pernmanent record or audit-trail of the well.
12 The flow integration software is based on the event logging of the positions of valve 12, 13 which controls the gas flow based on downloaded control strategy from the host component system 40 14 to determine when to start and stop flow calculation. The zero differential pressure, i.e. the millivolt reading of raw data before the valve is open, is used to scale the differential pressure values of the 16 cycle. The differential pressure span uses the latest calibrated or manually input value as it displays 17 on the event log of the calibration table. This application of the event logs to determine the flow 18 period and the establishment of the actual differential pressure zero base of each flow cycle constitntes 19 a system that eliminates gas measurement slippage caused by differential pressure zero shifting. Also the software allows insertion of the new parameters of scaling factors, gas composition, and basic flow 21 data, thereby providing another invention that effectively expedites the reintegration process to settle 22 any disputes between the producer and the pipeline operator.
23 The trend screen of FIG. 4, displays both analog data or process variable trends and the 24 digital event logs along with records of calibration and control-strategy changes, provides critical historical data to effect production optimization. Time bars located at both the top and bottom of the 26 screen can be scrolled to display data for the desired period. The top time bar displays the event logs 27 by means of data blocks. Data blocks can be color coded for easy recognition. If more than a single 28 event occurs at the remote location at the same time, the number of events which have occurred are 29 displayed on a data block, i.e. "2" and "3" as shown at the top time bar.
Icons to expand and contract the time scales are provided for the user to analyze and diagnose all the process variables on the trend 31 screen.
32 Markers can be inserted on the screen, and the time span thus marked can be scrolled.
33 Analog data is shown to be displayed beneath the bottom time bar, and event data is shown to be 34 displayed along the top time bar. The display feature with the dual time bars to correlate the process variable and the event logs constitute an invention. The well control program will be activated only 36 after the applicable control software and all configurable control parameters are downloaded from the 37 host component system. The remote component system is equipped with control capability to modify 38 a motorized choke, not shown, or to operate a bi-stable form of a solenoid valve 12 to control the flow 1 of gas delivered to the pipeline. A motorized choke can be used to control a gas well production 2 above 200 MCFD and bi-stable solenoid valve 12 is more effective for controlling a gas well with less 3 than 200 MCFD. Also an alarm software package, allowing the remote component system to initiate 4 transmission of an alarm message to the host component system 40 is a built in feature of the system.
A state-of-the-art telemetry package is also provided to allow data exchange with a host component 6 system computer loaded with the system of the present invention host component system software 7 package.
8 Referring again to FIG. 4, when a gas we1110 is initially open to production, an inrush of gas 9 will produce a sharp rise of the differential pressure 60, but static line pressure will remain unchanged. An immediate drop of both the tubing pressure 62 and casing pressure 64 will then be 11 noted. After a flowing period, the casing pressure will slowly rise in response to liquid moving up 12 through the tubing. A wide variation between the tubing pressure 62 and casing pressure 64 shows 13 continued liquid build up. When the differential pressure 60 reaches a predetermined control limit 14 valve 12 is closed to stop the gas flow. After valve 12 is closed and kept close, both the tubing pressure 62 and casing pressure 64 will increase until they reach stable points.
16 Referring again to FIG. 4, to the time upstream just before 12th hour, process variables 17 differential pressure 60, tubing pressure 62, and casing pressure 64, show a characterization or 18 signature of an pre-optimized well. After the 12th hour control parameter was downloaded to the 19 remote system the characteristic of 60, 62, and 64 show the characteristic of the well trying to stabilize after a new control parameter was installed. The well characteristic after 16th hour, shows a 21 stabilization of differential pressure 60, tubing pressure 62, and casing pressure 64 and this will 22 become an optimized signature of the well. This optimized characterization will remain for a period 23 of several months or longer.
24 Tubing pressure 62 can be used to diagnose leakage between the well head

10, separator (not shown) and line pressure 26. If leakage occurs, the tubing pressure profile will show a decline after 26 the well is shut.
27 The above control strategies allow the well to produce gas at a rate that matches the ability of 28 the reservoir and the line 18 or head 10 pressure. The event logs of the control strategies and the 29 presentation of the process variable give the operator an effective tool to determine the optimum production control strategy for each well. The trending data produced by the process of the present 31 invention shows if the well is optimiz.ed. Most wells, if properly optimized will remain optimized for 32 at least several months. Since most wells have their own unique signature or trending profile, a 33 trained operator can quickly diagnose any problem well through visual inspection of its trending 34 profile.
FIGS. 5 and 6 are flow-charts of an alternative embodiment of the remote component system 36 and the host component system of the prescnt invention.
37 In the operation of the present invention, at a gas well head 10 at a remote well site 38 transducers, and more specifically at least a differential pressure transducer 22, a temperature 1 transducer 24 and a static pressure line transducer 26 are placed in analog electric signal transmission 2 connection with a remote component system 32 installed at that remote well site. In preferred 3 embodiments, casing pressure transducer 28 and tubing pressure transducer 30 are also placed in 4 analog electric signal connection with the same remote component system 32.
Remote component system 32 is commissioned with all of the calibration, gas flow parameters, and control configurations 6 needed to operate the process of the present invention, for example in the form of the STELA software 7 listing submitted herewith and incorporated herein, as though set forth in its entirety. The input 8 device 34 scans, monitors and receives analog electric data signals from at least the differential 9 pmrssure transducer 22, temperature transducer 24 and static pressure line transducer 26, as well any other transducers associated with the well head area 10 and linked to the remote component system

11 32. The remote component system 32 also receives digital electric event data signals from associated

12 not shown end-devices such as a state-of-the-art tank level sensor, not shown, a state-of-the-art valve

13 position sensor, a state-of-the-art plunger arrival sensor, and the like.

14 This data is then electrically sent to input device 34, and thence transmitted to data logging manager 36 both for short term storage, and in preferred embodiments, for further transmission to 16 memory archiving data compression and data management system 38. As detailed below, the 17 compressed data is then transmitted to the host component system 40, see FIG. 3, for example by 18 remote telemetry system 42 for further processing. In preferred embodiments data management 19 system 38 is programmed to activate control modules 44 to activate control outputs 46 to, for example, open and close gas head 10 well valve 12 in real time, rather than on an arbitrary schedule, thereby 21 optimizing gas output from the well, and thereby, increasing both well efficiency and well life. In 22 preferred embodiments the activation of control module 44 and control output 46 is also managed 23 remotely by telemetry from host component system 40. In addition to these functions, In preferred 24 embodiments the remote component system 32 continuously scans, at a preset interval, and saves all active analog data received from transdueers 22, 24, 26, 28 and 30, and all digital data received from 26 digital electric event data signal transducers 12 and 16. That data is then compressed and stored both 27 in short term memory archiving data compression and data management system 38, for say about a 28 one month duration, and in preferred embodiments stored in mass storage system 48 for the life of the 29 well. Event data is stored in event logs as retrievable digital data which is time stamped. The data stored in the event log is then used to build up the trend files for both the process variables and event 31 logs, as shown in FIG. 4. Remote component system 32 is in electronic communication with host 32 component system 40. However, it should be noted that the remote component system 32 is fully 33 capable of stand-alone operation. It does not rely on the host to function, and is a typical distributed 34 architecture system design.
Referring again to flow-chart FIG. 3, the telemetry driver 48 of host component system 40 36 receives data from and sends data to remote telemetry driver 42. Data communication between the 37 host component system 40 and the remote component systems 32 is in serial format, for example via 38 the serial data port of an o$'the shelf computer and modem device, similar to the Internet system.

1 Since most gas well sites do not have conventional phone outlets, wireless telemetry data is the 2 preferred communication device. This data is then processed through memory archiving data 3 compression AGA-3 flow calculation processor 50 where it is be evaluated, for example, by displaying 4 it as a graphic display on graphic display user interface report generation monitor/input device 52, as 5 shown in FIG. 4, and discussed in detail above. The data is then stored both in short term memory in 6 module 50, and in preferred embodiments, in a host mass storage system 54.
Host component system 7 40 includes a computer which is capable of uploading data from the system of the present invention 8 remote component system 32, as well as downloading control strategies back to the remote component 9 system 32. The specifically designed computer software, again for example in the form of the STELA
10 software listing submitted herewith and incorporated herein, as though set forth in its entirety allows 11 the host component system 40 to splice the trending data seamlessly for the life of the well. The latest 12 versions of AGA-3 and AGA-8 are also loaded along with software to handle flow calculation to 13 determine gas flow volume. This allows the recalculation of gas volume for any time period using 14 modified parameters or scaling factors, and also provides a means which may be used to settle volume disputes between producers and pipeline operators. The system of the present invention host 16 component system is essentially an electronic chart integrator with no retracing or human intervention 17 required, thereby having high reproducability, and no opportunity for human error. The raw database 18 is maintained as a permanent record or audit-trail of the well.
19 The flow integration software is based on the event logging of the positions of valve 12 to determine when to start and stop flow calculation. The zero differential pressare, i.e. the millivolt 21 reading of raw data before the valve is open, is used to scale the differential pressure values of the 22 cycle. The differential pressure span uses the latest calibrated or manually input value as it displays 23 on the event log of the calibration table. This application of the event logs to determine the flow 24 period and the establishment of the actual differential pressure zero base of each flow cycle constitutes an invention that eliminates gas measurement slippage caused by differential pressure zero shifting.
26 Also the software allows insertion of the new parameters of scaling factors, gas composition, and basic 27 flow data, thereby providing another invention that effectively expedites the reintegration process to 28 settle any disputes between the producer and the pipeline operator.
29 In preferred embodiments, communication from with the remote component system 32 to the host component system 40 is on an interrupted mode. But, for example, any alarm at the remote 31 component system 32 is automatically reported to the host component system 40 immediately on a 32 "report-by-exception" basis. The host component system 40 is normally located in a central operating 33 office at which field personnel are present. The host component system 40 is programmed to scan a 34 plurality, or effectively, all of the remote component systems 32 in the field that it is designed to control, to update the trending files of each well, to generate a field wide report of daily gas flow 36 production data, all the related process variables, and any alarm events.
This report, normally 37 schedule to print each morning, may be quickly reviewed by the responsible field personnel to identify 38 wells with abnormal conditions, such as alarm situations and unusual production. Analysis of the 1 trends of these abnormal wells allows the responsible field personnel to quickly develop a corrective 2 action plan. For example, some wells may need modified control strategies from the host component 3 system 40 to the remote component system 32. Others may require on site visitation to correct the 4 problems. The trending analysis provide by the system of the present invention also allows the responsible field personnel to take action on a preventive maintenanee basis in order to prevent 6 damaging events, such as liquid spillage or freezing pipe from occurring has been proven to be a very 7 beneficial operating tool. In addition, the trending profile also provides diagnostic data to determine 8 if the correct orifice meter size is in use.
9 Both the producer and the pipeline operator can share the raw database produced by the process of the present invention. The host component system 40 is capable of archiving the raw and 11 integrated flow data for the accounting system of both the producer and the pipeline operator.
12 To optimize productivity of the gas well, reservoir trending of tubing and casing pressure 13 profiles via casing pressure transducer 28 and tubing pressure transducer 30 are vital data for proper 14 control strategy. To open the well, casing pressure must be allowed to build to a level where it must overcome the line pressure and liquid loading of the vertical tubing, not shown, to induce measurable 16 gas flow. For a high volume gas well, say of over 200 MCFD, a variable choke valve 12 may be used 17 to control the over ranging of the differential pressure and use the energy to extend the gas flow 18 volume. For wells under 200 MCFD, an on-off valve 12 controlled by a state-of-the-art bi-stable 19 solenoid is more effective in unloading the well at a cost of over ranging the differential pressure limit in the initial opening period. Once the differential pressure is detected to fall below about 10 or 15 21 inches, the remote system may be programmed to stop the gas flow by shutting valve 12. The ability 22 to stop the flow of the well at a high differential value results in more accurate gas flow 23 measurements, and also maintains a healthier gas reservoir pressure.
24 Accordingly, it is seen that several objects and advantages of the system of the present invention have been achieved:
26 a) Accuracy. With event logging of the position of the valves and the control software's 27 action, the system of the present invention can pinpoint the exact flow period and, consequently, 28 knows when to integrate data. FIG. 4 shows the display of event-logging of both the analog and 29 digital data. The digital data including open and/or closed valve positions, the arrival time of the plunger, and the time-stamped record of the digital inputs are displayed along with the analog data.
31 Unlike other solutions, this eliminates dependence on differential pressure data to determine on/off or 32 flow/no-flow conditions. The system of the present invention avoids zero-shifting errors by simply 33 stopping the flow calculation when the valve is shut-off. Therefore, the system of the present 34 invention solves the zero shifting problem.
b) Calibration economy. The system of the present invention eliminates the costly calibration 36 procedure of the flow measurement transducers. The system of the present invention achieves 37 software calibration from the PC keyboard instead of on-site adjustment.
38 c) Data storage capacity. The system of the present invention eliminates storage and 1 archiving limitations of the mechanical chart systems. The system of the present invention can store 2 data for the life of the well. Archiving or searching the raw data trend can be easily accomplished by 3 clicking the appropriate icons or buttons on the computer to select the desired data on the screen.
4 d) Does not rely on transducers for flow/no-flow determination. In systems that rely on transducers for flow/no-flow determination, the transducer must be absolutely infallible, and the gas 6 flow must be in an ideal condition with no turbulence at the low end, i.e.
below 10 inches of 7 differential pressure. These conditions cannot exist because as the gas flow rate approaches or falls 8 below 10 inches differential pressure, the data becomes erratic and unreliable. Also, transducers may 9 lose accuracy over time. Therefore, since the system of the present invention does not rely on transducers, but rather on event logging to indicate precisely when valves are open or closed and the 11 exact time of flow/no-flow periods the data is neither erratic nor unreliable.
12 e) Zero-shift correction. Unlike the electronic flow measurement systems that rely on the 13 differential pressure sensor for no-flow cutoff, this invention provides computer software written to 14 automatically and dynamically establish the true zero base, and therefore true differential pressure base, before opening the well to production on each intermittent cycle.
16 f) Retention of raw data. The system of the present invention logs raw analog data of the 17 weil's flow variables of line pressure, differential pressure, and temperature. The data are retained in 18 original unscaled millivolt values. Therefore, reintegration with a modified scaling factor and zero 19 base, as well as conversion to engineering values can be easily achieved with software. Measurement disputes can be resolved fairly because the original data can be retrieved and used for recalculation by 21 both parties using the established AGA formulas.
22 g) Uncompromised audit trail. Unlike the currently used chart recorders, the system of the 23 present invention does not need to retrace or manipulate data. The original, raw data are available for 24 the life of the well. Any need for recalculation can be met because the raw databases of line pressure, differential pressure, and temperature are easily accessible.
26 h) Programmed control instructions. Programmed instructions can shut in the well, in real 27 time, when it falls below the accurate differential pressure range at about 10 inches and/or when other 28 parameters (i.e., liquid loading problems) exist. These control actions maintain the flow at accurate 29 ranges while maintaining a high bottom hole pressure. Exerting control over the principles of gas extraction can extend the life of the reserve while keeping the differential pressure at an accurate 31 flowing rate.
32 k) Event logging. The event log is a time-stamped record of the digital inputs; for example, 33 the valve open and closed positions or the plunger arrival status. This eliminates the dependence on 34 differential pressure data alone to determine the on-off or flow-no-flow conditions.
1) Full graphical presentation of all vital analog and digital readings on a single screen.
36 The trend screen, for example as shown in FIG. 4, displays color-coded temperature and 37 pressure readings as a graph along the analytical time bar at the bottom of the screen. Corresponding 38 values display in fields below the time bar. This data display provides the vital information needed 1 for flow analysis.
2 Along the digital time bar at top of the screen, color-coded blocks identify specific well 3 events. Each block marks an event that is logged on the bar at the time it occurs; if multiple events 4 occur at a single time point, the block indicates the number of events.
Examples of well events include plunger arrival, changes in valve position, changes in the level of the storage tank that stores 6 produced water and distillate, changes in control parameters, application of AGA-3 parameters, 7 calibration, and others. A message box can be opened at an event block on the trend screen which 8 itemizes each well event in detail. For example, the message for a selected event block might inform 9 the user that the well was shut-in on a specific date and time.
Should data require reintegration, the operator can specify the time span to be reintegrated by 11 using a hairline marker available on the button bar. Data not visible on the screen can be accessed by 12 a scroll button.
13 The graphical presentation of temperature and pressure data and the digital information 14 available through event log detail provide both optimum flow analysis and indisputable measurement of continuous and intermittent flow.
16 Unlike the state-of-the-art circular chart recording which covers only eight days, the system 17 of the present invention trend screen, such as in FIG. 5, has no such time limitation and seamlessly 18 displays all process variables, including tubing and casing pressure trending profiles which yield 19 valuable information about the reservoir performance. This invention allows the operator to analyze the well's behavior to determine the best strategy for flow control and elimination of slippage. With 21 the precise stamping of the on-off valve position, the operator does not have to rely on arbitrarily 22 assigned timing periods of opening and closing the well to flow.
23 Referring again to FIG. 4, this basic version of the trend screen, which is integral to the 24 system of the present invention methodology and software package is uscd with software which is designed to duplicate the actual characteristics of analog and digital data with respect to time. By 26 means of time stamping, the system of the present invention records the high and low peak values of 27 the analog data for real time analysis. The system of the present invention methodology combines 28 flow parameters of static line pressure, differential pressure, and temperature analog data, and shut-in 29 tubing valve status as digital data, and software control operation to provide an auditable electronic flow measurement system for custody transfer of natural gas. The system of the present invention is 31 capable of resolving measurement slippage associated with intermittent or erratic flow conditions.
32 The system of the present invention also simplifies calibration procedure of the analog instruments 33 because it retains the raw database for software calibration.
34 In preferred embodiments, the system of the present invention Trend screen provides easy to interpret and analyze color-coded well data. The user selects the analog data to display data such as 36 casing pressure, tubing pressure, line pressure, or differential pressure, line or glycol temperatures, 37 and so on, on the time line at the lower edge of the screen. The user can also select well events to be 38 time stamped, i.e. records of digital inputs such as open and closed positions of the value or plunger . , ' CA 02320875 2008-05-29 ~-arrival status, which are displayed on the time line at the upper edge of screen. With the two displays of analog data and digital data, the user of the system of the present invention methodology has precise measurements of flow, precise knowledge of the exact flow period, the ability to auto-calibrate analog instruments, and the ability to reintegrate raw data when corrections are needed, as for example, calculations based on the wrong size orifice plate or calculations based on erroneous gas parameters, could be easily corrected with this invention.
It is therefore seen that the present invention provides a highly reliable, more accurate, and more economical methodology that can be used to precisely measure flow volume without time span limitations, accurately pinpoint flow and no-flow situations, and retain raw data to ensure accurate reintegration. As a result, producers will benefit because production efficiency relies on the analytical quality of the flow and pressure trending of the well to diagnose production problems and optintize the liquid removal process, producers will benefit by having a tool to effectively plan a preventive maintenance schedule for the well and control the gas reserve. In addition, both the seller and purchaser benefit by being able to resolve disputes over unaccounted-for gas volumes through the reintegration process with full graphical presentation of all vital analog and digital components of the measurement system and a common raw database. The event logging of the digitat data of on-and-off conditions of the valve or shut-in end-devices and trending of the flow parameters (static pressure, differential pressure, and temperature analog data) completely eliminate the measurement slippage problem. Because the trending data are unscaled or in the original raw format (millivolt values), reintegration, as well as rescaling flow or other parameters, is accomplished with software.
Therefore, any disputes of the calculated flow data of any period can be quickly and easily resolved to the satisfaction of the seller and purchaser.
While the above description contains many specificities, these should not be construed as linritations on the scope of the invention, but rather as an exemplification of one prefeffed embodiment thereof. Many other variations are possible. For example, the host component system 40 of the present invention may be loaded into a notebook computer having a modem and will allow direct connection with the system of the present invention remote component system from any phone line or cell phone to interrogate or upload-download control strategies from or to the remote component system 32.
The foregoing exemplary descriptions and the illustrative preferred embodiments of the present invention have been explained in the drawings and described in detail, with varying modifications and alternative embodiments being taught. While the invention has been so shown, described and illustrated, it should be understood by those skilled in the art that equivalent changes in form and detail may be made therein without departing from the true spirit and scope of the invention, and that the scope of the present invention is to be limited only to the claims except as precluded by the prior art. Moreover, the invention as disclosed herein, may be suitably practiced in the absence of the specific elements which are disclosed herein. Accordingly, the teaching of the present invention is intended to embrace all such changes, modifications, and variations.

Claims

1. A method for measuring the volume and rate of gas well flow from a gas well head, equipped with various types of flow metering devices, 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, means for determining the position of a gas flow valve, means for sensing plunger arrival time, 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, wherein said analog electric data is transmitted as analog electric data signals;
transmitting digital electric event data as a function of time to the input portion of said first electric component system, wherein said digital electric event data is transmitted as digital electric event data signals;
transmitting said analog electric data signals from at least the differential pressure transducer, the temperature transducer, and the static pressure line transducer to a data logging manager for storage;
transmitting said digital electric event data signals to a data logging manager for storage;
and then presenting analog electric data from said analog electric data signals and digital electric event data from said digital electric event data signals for display and analysis of well characteristics and events, including volume and rate of gas well flow from the gas well head to which it is in operative communication.

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

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

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

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

8. The method of any one of claims 1 to 7 wherein a casing pressure transducer and a tubing pressure transducer in operative communication with the gas well site are also placed in analog electric signal connection with said first component system.

9. The method 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 trending and gas volume flow.

10. The method of any one of claims 1 to 9 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 event 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, including volume and rate of gas well flow from the gas well head.

11. The method of claim 10 wherein said stored analog electric data and digital electric event data are used for well control.

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

13. The method of claim 12 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 visible display.

14. The method of claim 13 wherein said visible display is on a monitor screen.

15. The method 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 visible display.

16. The method of any one of claims 1 to 15 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 the transducers are located.