REMOTE INTELLIGENCE EXPANDS SCADA'S USE UPSTREAM

March 30, 1992
Guntis Moritis Production Editor Improved electronics and computer equipment, available at much less cost, are replacing older components and increasing the number of oil and gas fields automated with scada (supervisory and control and data acquisition) systems. These new systems include components such as "intelligent" or "smart" RTUs (remote terminal units) that process data at the lease location. This remote "intelligence" can maintain supervisory control even after losing communication
Guntis Moritis
Production Editor

Improved electronics and computer equipment, available at much less cost, are replacing older components and increasing the number of oil and gas fields automated with scada (supervisory and control and data acquisition) systems. These new systems include components such as "intelligent" or "smart" RTUs (remote terminal units) that process data at the lease location.

This remote "intelligence" can maintain supervisory control even after losing communication links. In other words, these newer systems offer distributed architecture or control.

Unlike older systems, designs of the newer generation of components include nonproprietary data transmission protocols.

Because there is a mix of old and new technologies in the field, the term scada often refers to a number of different generations of automation technology. The simpler systems might not fall into the true scada category. Likewise, some complex systems can be a part of a DCS (distributed control systems); or vice versa, the DCS might be part of the scada system.

The basic function of a scada system is to respond to various monitor and control elements. Then scada transmits this information to a central location commonly called an MTU (master terminal unit) or a host computer. Fig. 1, diagrams one such system. The distance between the remote location and MTU is usually measured in miles.

Some of the main uses of scada are for pump-off control, gas flow measurements, facility process control, custody transfer, gas chromatography, engine and pump control, process control, power transmission switching and control, tank level sensing, alarms for the site, and leaving an audit trail for the operations.

A microprocessor-based rod pump controller is shown in Fig. 2. One estimate of the improvement that can be made from pump-off controllers is:

  • Production will increase 3%.

  • Lift-equipment failure will decrease 14%.

  • Energy consumption should stay about the same.

Likewise the other components in the scada system can benefit the operator by increasing lease profits and provide more safety to both personnel and the environment.

SCADA MARKET

According to Tech-Marc, a firm specializing in analyzing the market for scada, the North American scada market will grow from $600 million in 1990 to $819 million in 1995.

This market includes master station equipment, RTUS, software, and services.

As hardware and software capabilities have expanded, the definition of a scada systems has broadened. In the past, scada systems usually consisted of a "dumb" RTU that collected raw data to send to the MTU. All of the data were then processed and analyzed centrally. The central MTU carried out the control on a real-time basis.

Now "intelligent" RTUs, with sophisticated software, can distribute the control at the lease location. The MTU then serves more as a data collection and analysis point often not having to function in a real-time mode.

In a minimal cost installation, the MTU site can even be eliminated. In this case, the RTU processes information and then sends alarms or event status directly to operators who physically could be in a number of different locations.

To save costs on communications systems, the data collected might be stored at the remote location and retrieved by the central computer as an event report or by the use of standby and scanning by exception.

Infrequent data collection, such as once or four times/day, is preferred for routine lease data, especially for relatively stable operations. On the other hand, where there is a need such as monitoring a lease that has significant H2S concentration, polling often is as frequent as 4-min intervals.

To check the large volume of data gathered in a 24 hr period, Texaco in its West Texas operation uses a 6 a.m. scan to report wells with potential problems. 2 Also, expert systems have the potential for summarizing the massive amount of data that can be generated.

Besides oil and gas lease applications, scada is also being installed to control mobile lease servicing equipment. Nowsco Well Service Ltd. has applied the technology for controlling equipment during hydraulic fracturing. 3

For the RTU portion, Nowsco combined a PLC (programmable logic controller) and DOS (disk operating system) with STD bus hardware. The MTU is a standard portable personal computer.

The RTU, located on the blender truck, controls and monitors the frac job. The MTU, in another vehicle on the location, allows the operator to program the job, monitor the changing conditions, and remotely interface with the switches and knobs on the main control console. Communication between the RTU and MTU is through standard RS232 ports.

SCADA DESIGN

Although scada offers a potential for increasing lease profit with increased safety and environmental protection, there can also be severe problems because of improper installation, incompatible hardware and software, and inexperienced operators.

Because scada components can be configured with many different combinations of vendors, hardware, and software, compatibility problems can occur.

Experts well versed in scada systems may not have extensive knowledge about upstream oil and gas technology.

To lessen these problems, Oryx Energy Co. prepared a document to serve as a company standard and tutorial text. 4 In this document, 18 specific areas were considered. These include:

  1. Language

  2. Processor

  3. Analog/digital (A/D) conversions

  4. Polling frequency and speed

  5. Data integrity

  6. Memory

  7. Power consumption

  8. Solar power

  9. Protocol

  10. Inputs and outputs

  11. High-speed accumulators

  12. Remote terminal units (RTUS)

  13. Programmable logic controllers (PLCs)

  14. Data concentrators

  15. Host computer

  16. Host computer software

  17. Communications

  18. Planning and design.

The Oryx document narrowed the number of vendors and equipment used by the company. One software package was selected that could address all standard hardware.

Both cost effectiveness in small operations and adequacy for large field installations determined component selection.

The principle functions of Oryx's system were for pump-off control, gas flow computation, and process control. Additional applications were for:

  • Monitoring

  • Report generation

  • Data analysis

  • Data communications

  • Well testing

  • Leak detection

  • Flow measuring

  • Automatic call out

  • Platform shut-in for hurricanes

  • VSD frequency adjustment

  • Stuffing box leak detection

  • H2S and CO2 monitoring.

As discussed before, the newer scada systems are taking advantage of the distributed architecture. One prediction is that the scada systems of the 1990s will be distributed in nature like their cousin, the DCS system. These systems will include user interfaces based on UNIX workstations that employ X windows and open software interface such as Motif 5 Fig. 3 diagrams one such system.

The X windows software allows one video monitor to show multiple displays (windows) of information. Extensions of X windows are also available.

Besides Motif, another, older GUI (graphical user interface) in use is Open Look. 6

With this advanced software, the screens reside on the central host computer and only data are sent from the remote location. Not having to send the data screens saves considerable transmission time and cost.

COMMUNICATIONS

Communications systems can include VHF/UHF/900-Mhz radio, microwave, satellite links, telephone lines, and fiber optic lines. Systems can be either leased, trunked, or owned. The VHF/UHF range includes the 150 Mhz and 450 Mhz ranges that have restrictive splinter frequencies, common in scada applications.

The 900 Mhz range of frequencies are for data only, no voice and are part of the UHF range.

Microwave bands usually refer to frequency ranges greater than 1 Ghz, although some refer to the 950 Mhz and even the 850 Mhz frequency ranges as microwave.

Picking the right communications system depends on the existing infrastructure in the area. In a metropolitan area, telephone lines frequently provide the best communication.

Cellular telephones can provide a means to send data if transmissions are kept infrequent. Fig. 4 shows a low-cost cellular system that can communicate in English. The system's status can be checked from any telephone.

These cellular setups allow the operator to:

  • Monitor compressor operation, high/low tank level, high/low pressure, pit level, heater and refrigeration temperatures, etc.

  • Start pumps, switches, valves, lights, etc.

  • Detect high noise level caused by gas venting

  • Have the unit dial a number of different telephone numbers, in sequence, until the alarm in acknowledged

  • Restrict access.

Depending on the specific requirements of the lease, costs of these relatively simple cellular monitors range from about $8,000 to $9,500/site. They are also available on a lease basis.

Trunked radio lines, such as used by Meridian Oil in its San Juan basin coalbed methane gas production, operate similar to telephone lines. 7 The customer can buy a part of a system's capacity and pay hookup fees for each well site. The benefits include reducing capital investment by not having to purchase the radios, antennas, and repeater sites. All this equipment is available on a lease basis.

Meridian's installations are costing from $8,000 to $18,000/well site. This includes a turnkey installation consisting of electronic flow measurement and remote terminal units, measurement and control elements, field wiring, and support services.

Amoco's operation in the same San Juan area, unlike Meridian, is continuing its tradition of using company-owned communications equipment. In 1991, about 30 newer RTUs were in place. This is planned to increase by 750 in 1992 and 1993, and possibly more in the following years.

Because of the remoteness of many offshore operations, satellites offer a convenient and reliable means of communications. Where infrastructures exist, such as in the Gulf of Mexico, offshore communications can also use radio, microwave, or cellular links.

Small aperture earth stations are common for connecting remote offshore rigs to head offices.

The international satellite system (Intelsat) has a monopoly over international satellite switched services. Rule changes are being made by non-Intelsat satellites to gain entry for fear that most traffic is migrating to switched networks and away from private satellites.

There have been studies made that suggest ultra small satellite terminals can provide economical low-speed scada communications. One estimates is that these spot-beam satellites are less expensive than the $150/month per site for leased telephone lines. Each terminal's price would be about $1,500 if 500,000 units are sold. A test satellite of this type is expected to be launched in 1993.

In some areas of the U.S., multiaddress frequencies can be hard to obtain. To alleviate congestion, the Federal Communications Commission (FCC) has recently allocated some additional frequencies in the range of 932/941 Mhz. Depending on the demand, awarding of these frequencies involves a lottery and stipulations that the user may not obtain more than one license within a designated area.

The frequencies in the 900 Mhz range need a line of sight between antennas for communication. Unlike the lower bands, no antenna height restrictions apply to the 900 Mhz band. The lower frequency bands allow transmission around objects.

In the 900 Mhz range, a pair of frequencies is usually used for communications. One frequency is for sending, the other for receiving. This allows full-duplex operation, but will prevent two RTUs from communicating with each other unless each RTU contains two separate transmission frequencies.

Communications on the lower frequencies are at half duplex. In other words, one device has to stop transmitting before the other one can start.

Although there is a scarcity of radio frequencies in congested areas such as metropolitan areas, for most of the U.S., frequencies are available by filling out the proper paper work. According to the FCC, the scarcity sometimes is exaggerated by companies that may want to act as middle men for securing licenses.

Another choice in communications is whether to pick analog or digital radios. Digital devices offer greater transmission speeds but alignment is more critical.9

For smaller sites, analog devices can be more economical. These devices operate at lower speed but are more tolerant of the harsh environment found in many oil and production locations. Lightning, heat, cold, offshore, electric surges, and gases such as H2S and CO2 are some of the environmental factors that could effect the devices.

One recent trend in communications is to-produce computer synthesized voices. Information sent as synthesized voices, generated from either a field RTU or from the MTU, can be more descriptive in communicating problems over regular or cellular telephone links.

Equipment now is also available that can take measurements, calculate statistics, and send the results automatically to a facsimile machine.

Some communication choices are: 6

  • For cellular to avoid placing too many calls to the remote, the automatic well test function should be in the remote device.

  • With dedicated leased telephone lines to the remotes, the automatic well test functions can be placed in the MTU, thus requiring a simpler remote unit.

  • For radio, uploaded historical data from a remote unit must package data into small chunks because radio is subject to frequent interference.

  • In a cellular system, historical data need to be in large chunks to lessen transmission time.

Unlike DCS systems, scada lends itself to open communications architecture. The DCS systems, because they operates on a real-time basis, mostly use proprietary communications protocols.

DCS PLUS SCADA

For large production facilities, both offshore and onshore, scada can be combined with DCS systems.

One example is the recently installed system in BP's Wytch Farm operation in southern England. The field is producing about 62,500 bo/d and is the largest onshore oil field in Western Europe.

The $4.7 million system combines scada and DCS to supervise the well sites, control oil processing at the Wytch Heath gathering station, and oversee the pipeline operations.

Other functions include supervising seawater extraction and water injection, the export of liquefied gas by rail tanker and of natural gas to the British gas grid, and integrating a host of third-party supplied equipment including the emergency shut down (ESD), and fire and gas detection systems.

Each of the well sites, located at distances up to 9 km for the gathering station, is tied into the system with fiber optic links.

The traditional process control functions of a conventional DCS are combined with the broader data acquisition and supervisory functions of a scada system that operates over distances of up to 90 km (56 miles).

By bringing all operational, environmental, and safety-related information to one place and display (Fig. 5), one operator can supervise and control the entire installation.

This type of control would not have been possible with a traditional process control system and a separate scada system. The system is about one-third conventional process control and about two-thirds scada.

Combining DCS with scada is also being done with gas plants in the U.S. A number of plants, such as the one for the LaBarge field in Wyoming, use a DCS system to control the scada interface at the well. By combining these systems, wells can be controlled rapidly to prevent gas flaring if the plant is forced to reduce intake volume.

DCS systems are used in most cases on large offshore oil and gas platforms for process control. But a number also include a scada system for collecting data for presentations, logging, and to prepare reports.

DCS systems, such as the one recently installed on the Veslefrikk platform, offshore Norway, 10 distribute processing power to the module level, eliminating the need for a central process computer. The control is distributed but the data acquisition and integration is centralized.

In some offshore areas scada systems include PLCS. The PLCs replaced many of previously common pneumatic-based production control and safety systems. One such system was installed by Kerr-McGee on its High Island 22A platform in the Gulf of Mexico." The PLCs provide for a more direct interface with the platforms safety systems and Kerr-McGee's Gulf-wide scada system.

REPLACEMENT SYSTEMS

Several generations of scada are still in use. Especially for the old, large, and more expensive systems, companies tend to "milk" them for as long as possible before considering replacements.

But as parts for older systems become harder to get, the systems become inadequate for the operation, or maintenance costs increase, companies have to choose whether to replace the old system entirely or modify it.

Because both communications and computer equipment have made rapid changes in the last few years, there are significant advantages in replacing an entire system.

The upgraded systems usually enhance monitoring, add new sensor points, incorporate new software, produce additional reports, and increase the array of computers networked together.

Valve control, gas flow measurement in one remote device, and multiple user access are the functions of scada that were not available in the older systems. The older systems were generally also more manpower intensive.

One scada system that was recently changed over was Shell Canada Ltd.'s Burnt Timber gas complex located in the foothills of southern Alberta. 12

Shell Canada's new scada system has a third-party package as a platform for controlling four gas fields and one oil field.

The wells and compressor stations are in remote areas in,here it can take up to 1 hr for an operator to drive from one well to another in the same field. Moving from the most southerly well to the most northerly well can take 4 hr or more depending on weather conditions.

Remote monitoring and control reduces check-out time, provides current data on the well's operation, and gives the ability to control the well as product demand changes or in meeting an emergency situation.

Shell Canada's original scada software had been jointly developed with Shell Oil Co. After 1980, independent development paths were needed because of differing operational requirements.

The software eventually became outdated, while becoming increasingly difficult to modify and maintain. Many day-to-day changes had to be made, contributing to an ever increasing backlog of field maintenance requests.

Two of Shell Canada's key design factors were:

  1. To accept the basic third-party package design as is.

  2. Use a template concept where applications such as metering, choke valve control, and emergency shutdown were included in even, installation.

One main feature of Shell Canada's system is to keep the scanning up time at a maximum. A redundant MTU containing two separate computers provides added security for the system. One computer runs the scada applications while the other is on warm standby, waiting to take over if the first fails.

Field staff also have the says to dial-in from home using personal computers. This is very useful during off hours when the field staff is not on site.

Communication within the complex is mostly light-route microwave system. Because of the complex terrain and distances involved, this system proved more economical than buried cable or a complex network of UHF radios.

The microwave system architecture is based on a star-like structure with all routing information passing through a central station located in the nearest town.

A total of five repeater stations and six out-stations are necessary to provide total field coverage. In one instance, three microwave hops are required to get data from the field office scada computer to the central microwave station, and then another four hops out to a particular gas field, for a total of seven hops.

To model 50 wells and three compressor stations, approximately 6,000 status, multi-status, analogs, set-points, and controls were configured into the data base. Roughly 250 additional custom displays also had to be incorporated into the system. Along with this went all the associated communication and polling information into respective data bases.

The complex required 13 consoles. Locations included the field office, compressor stations, gas plants, and one console in the nearest community. Printers were also located with each consul.

Communication baud rates range from 300 to 4,800 for scanning purposes, 2,400 for printers, and from 9,600 to 19,200 for the consoles. The remote dial-ups are served by 2,400 lines.

Cost of Shell Canada's project was $615,000.

REFERENCES

  1. Blackford, T.A., Dunn, J.R., and Joseck, R.R., "Analysis indicates benefits of supervisory pump-off control," OGJ, July, 1, 1991, pp. 66-63.

  2. Swartzlander, H.R., "Remote units eliminate unproductive pumping," OGJ, Sept. 3, 1990, pp. 58-61.

  3. Eng, W.W., "Blending Technology for a Mobile Scada System," Entelec Fall Seminar, Oct. 24-25, 1991, Houston.

  4. Carroll, L.B., Bolin, "'.D., Luke, G.B., Richardson, J.D., Vardeman, R.D., and Jentsch, W.A., "A Company Standard for SCADA Systems Serves Large or Small Field Operations," Entelec Fall Seminar, Houston, Oct. 24-25, 1991.

  5. Derynck, R., "Next Generation of Supervisory Control Systems," Entelec Fall Seminar, Oct. 24-25, 1991, Houston.

  6. Evans, J.W., "Total design in field management," Entelec Fall Seminar, Oct. 24-25, 1991, Houston.

  7. Rayborn, K.F., Flowers, B., and Johnson, J., "Telemetry and process instruments control coal gas production," OGJ, Nov. 12, 1990.

  8. Fairbanks, B., "Application of Spot Beam Satellite to Scada communications," Entelec Fall Seminar, Oct. 24-27;, 1991, Houston.

  9. Taylor, D.S., "Common Problems with Multiple Address Radio Systems and Some Possible Solutions," Entelec Fall Seminar, Oct. 2425, 1991, Houston.

  10. "Modularity adds flexibility to process control on Veslefrikk," OGJ, Mar. 25, 1991, pp. 49-50.

  11. Thibodeaux, "PLC's used for offshore production-platform control," OGJ, July 18, 1988. pp 38-43.

  12. McEwen, J.N., "Scada system by third party cuts staffing in gas complex," OGJ, May 13, 1991, pp. 43-48.

Copyright 1992 Oil & Gas Journal. All Rights Reserved.