TELEMETRY AND PROCESS INSTRUMENTS CONTROL COAL GAS PRODUCTION

Nov. 12, 1990
Kenneth F. Raybon Meridian Oil Inc. Farmington, N.M. Bill Flowers Fisher Controls Marshalltown, Iowa Jim Johnson Vinson Supply Co. Farmington, N.M. Telemetry and process instrumentation is assisting in the production of gas from the Fruitland coal seams in the San Juan basin of New Mexico and Southern Colorado (Fig. 1). Since 1987, Meridian Oil, a wholly owned subsidiary of Burlington Resources, has been automating individual wells, pipelines, compressor stations, and produced water facilities
Kenneth F. Raybon
Meridian Oil Inc.
Farmington, N.M.
Bill Flowers
Fisher Controls
Marshalltown, Iowa
Jim Johnson
Vinson Supply Co.
Farmington, N.M.

Telemetry and process instrumentation is assisting in the production of gas from the Fruitland coal seams in the San Juan basin of New Mexico and Southern Colorado (Fig. 1).

Since 1987, Meridian Oil, a wholly owned subsidiary of Burlington Resources, has been automating individual wells, pipelines, compressor stations, and produced water facilities in the San Juan basin.

The automation system has improved manpower utilization, virtually eliminated gas flaring, and provided operations personnel with well head flow and pressure control, as well as a wealth of ongoing information and control of major field operations.

COAL-SEAM GAS

Interest in coal-seam gas production in the area dates back to the 1950s. The major deterrents at that time to widespread development were low gas prices and the large quantity of water that was produced with the gas.

Production of gas in the San Juan basin by conventional means dates back to 1896, but serious interest in coal seam gas production from the area did not begin until the 1950s, primarily encouraged by the construction of pipelines to serve the large California and West Coast markets.

The San Juan basin, ranking only behind the Hugoton field in gas production, is approximately 100 miles wide, 140 miles long, and has a surface area of about 7,500 sq miles.

The Fruitland coal-seam formation ranges in thickness from less than 100 ft to more than 600 ft, and is present throughout the San Juan basin at depths of up to 4,200 ft. Until recently, the Fruitland formation was considered nothing more than a hindrance in efforts to drill through the formation to reach the deeper sandstone reservoirs.

In 1953, the first coal-seam gas producer was completed in the New Mexico portion of the San Juan basin. Subsequent drilling took place in the 1970s, but in both cases, the low price of gas and the large quantity of water that was produced with the gas were deterrents to continued development.

TAX CREDIT

It was not until the late 1980s that development of coal-seam gas was rekindled, motivated by a better understanding of coal-seam gas production technology and by the enactment by the U.S. Congress of the fuel tax credit in 1980 that allowed a direct production tax credit for coal-seam gas.

The tax credit was originally applicable only to production from new wells drilled prior to Jan. 1, 1990. When the windfall profit tax (of which the coal-seam tax credit was part of the original legislation) was repealed in 1988, the nonconventional-fuel tax credit was preserved. In fact, the fuel tax credit was amended to include a 1-year extension, to Jan. 1, 1991, of the cutoff date for drilling new wells and a provision for the indefinite carry over of the credit.

SAN JUAN BASIN

Before launching the aggressive drilling program that is on-going in the San Juan basin, Meridian conducted a 20-well pilot program beginning in 1986. After the final pilot well was brought on stream in February 1988, gross production from the 20 wells amounted to 28 MMcfd.

As formation dewatering proceeded, the combined production rate rose to a maximum daily rate of 60 MMcfd with a sustained rate of over 50 MMcfd. Some Individual wells in the basin are among the most prolific coalseam gas wells in the world. One produces more than 15 MMcfd and several others 10 MMcfd.

When drilling began in earnest in 1986, Meridian initiated discussions with Vinson Supply Co. in Farmington and with Fisher Controls.

Initial discussions centered on having flow only measurement capabilities. After further consideration, it was decided to transmit more data via a communication system back to Meridian's regional production office in Farmington.

Once the parameters were established, an initial order was placed for six data gathering, control, and communications units to be placed on remote gas-well locations.

REMOTE CONTROLLERS

At the heart of Meridian's new field control and communication system was the remote operations controller (ROC) developed and manufactured by Fisher. The ROC is a self-contained, freestanding unit that provides control, data acquisition, totalizing, calculating, alarming, and communications functions.

Installed in a remote field location, the ROC connects directly to existing measurement and control equipment. The unit sends data to, and receives data from, a host computer in Farmington. The communications channel is an 800-mhz trunked radio communication link.

The ROC unit, without batteries or power supply, weighs 175 lb and is mounted on a 400-lb concrete base to provide stability.

The major components of the ROC units currently being installed in the San Juan basin are shown in Fig. 2 and include the following:

  • Equipment housing which contains all the ROC components. Attached to the housing frame are an electronics enclosure, a battery box mounted on the frame base, and a junction box located behind the front cover to provide terminations for field wiring.

  • Data acquisition control/power and communications module (DAC/PAC). This module is microcomputer-based and performs input/output scanning communications, flow calculations, sequential control, closed loop control, and data-storage functions.

  • Scaling, fusing, and 1/0 board (SFIO) provides all connections between the field wiring junction box and the DAC/PAC module.

  • Termination, power, and communications board (TPC) provides connections between the DAC/PAC, power supply, SFIO board, and radio.

  • Line or solar power supply that provides 12 v power to the electronics and consists of batteries, 24-v power converter for field transmitters, battery charger (line powered units), and solar regulatory and solar panels (solar powered units).

  • Integral radio and antenna.

TRUNKING SYSTEM

The first well to be automated became operational in October 1987, transmitting data back to Meridian and Vinson offices in Farmington via a 450-mhz band radio system. While this band provided good propagation characteristics and allowed use of low-cost equipment, it was designed primarily for voice communications and wasn't well suited to telemetry applications.

While a study of alternatives was being made, the Federal Communications Commission revised its regulations governing the use of specialized mobile radio (SMR) trunking frequencies. These changes made it possible for the owners to determine how trunked systems could be used.

An owner wanting to use trunking frequencies for telemetry as well as voice, could do so and still operate within FCC guidelines. Fisher, after consulting with the FCC and Meridian, felt that a trunking system offered the best solution to the communications problem.

After a cost analysis, Fisher decided that the best approach was to offer communications services in the same manner as a telephone utility. The customer (Meridian) elected to buy system capacity and pay hookup fees for each well site.

Analysis also showed that a single customer would not make the system feasible from a financial standpoint. However, since trunking systems are intended for multiple subscribers, the projected usage of the system by other operators in the area made the undertaking a sound investment.

Benefits of the system to users included not having to invest in their own communications networks. It also meant that they could minimize their capital investment by purchasing or leasing only the radios and antennas installed at well sites, in vehicles, and in offices. Also, customers would not have to own and operate repeater sites.

Other benefits included having a single system for both voice and data, eliminating the need for separate systems, and wide-area coverage. New well site installations could be placed on-line quickly.

Each trunked site would have 5 channels which would be expandable to 20 for good channel availability and accessibility. In this manner, a large volume of both voice and data traffic could be handled by the system without interference or "blocking."

In late 1988, Fisher had General Electric GE-MARC VE trunked radio equipment installed at four locations in the San Juan basin, near the towns of Farmington, Blanco, and Lybrook in New Mexico and near Mancos, Colo.

Each site was equipped with five repeater channels. All the repeater sites were also equipped with 45-mhz telephone interconnect. All equipment was operational early in 1989.

During 1990, a system expansion was undertaken that added a fifth repeater site in the eastern part of Meridian's field. At the same time, the original 45-mhz site telephone interconnect was replaced with a microwave system at each repeater site.

Today, over 200 units (Fig. 3) have been installed on Meridian sites and are providing Meridian with considerably

| more operational information and control than the early installations. They provide the following information:

  • Flow calculation (AGA 3 NX19), pressure, temperature, and differential pressure across orifice plate

  • Casing pressure

  • Tubing pressure

  • Tank level

  • Disposal well injection flow

  • Disposal well injection pressure

  • Compressor status (on/off).

Today, the system not only provides the above information, but has been expanded to include continuous, updated data on the following:

  • Downhole pressure and temperature on pressure-observation wells

  • Produced water management for pumped water to central gathering facilities, calculated produced water including changes in tank levels and pumped water, and water pipeline monitoring and isolation

  • Compressor station monitoring

  • Gas analysis, CO2 at processing facility, and H2S at well sites

  • Flow control

  • Flow control with pressure override.

COMPUTER MONITORING

Located at Meridian's regional offices in Farmington is a Fisher master operations computer (MOC), a PC-compatible workstation which runs Fisher-developed applications software.

The MOC is the data collection and processing center for the field automation system. Here, reports are generated; operators can view each well site through user-generated displays; and commands, such as changing flow rates or AGA flow parameters, can be issued to individual ROCs from the keyboard. These data are available via the computer screen as well as in a hard copy format and are received by Meridian hourly or on demand.

Typical data displayed by the computer screen on a specific well are illustrated in Fig. 4. In addition to showing tubing and casing pressure, the screen also shows watertank level, water produced, and water pumped to the disposal facility.

Differential pressure across the orifice plate, static pressure in the gathering systems, and temperature of the flowing gas are also presented.

The upper right-hand part of the screen shows the production set point, the current rate of production, and the actual cumulative production for the current 24-hr period. The set point or flow rate can be changed from the MOC in Farmington to adjust the flow rate to the desired level.

Fig. 5 is a computer screen showing a natural gas delivery point to El Paso Natural Gas Co. From its master station, Meridian can create a set point to deliver predetermined volumes. The picture indicates that no gas is currently being delivered and that all produced gas is being directed to the Val Verde gas processing plant.

Each ROC is also configured to provide continuous information on selected pressure and temperature observation wells as shown in Fig. 6. These data assist Meridian reservoir engineers in monitoring down-hole conditions at various points in the field.

Cumulative information for a 30-day period is presented in a trend line format, as shown in Fig. 7.

Each Meridian field foreman also has access to production data for each of the wells for which he is responsible. As shown in Fig. 8, the current production rate is displayed for each well, and an asterisk beside the well number indicates that it is equipped with flow control capability.

In addition to providing Meridian with a broad spectrum of operating data, the system allows identification and immediate reaction to any malfunction in the gas production system. For example, if a pressure buildup occurs in the gathering system, the ROC senses it from a pressure transmitter at the well site and shifts automatically from controlling the well flow to controlling the gathering system pressure.

This function, called pressure override, prevents flaring of produced gas into the atmosphere. Company officials estimate that this capability alone can save them from flaring up to $10,000 of gas/hr from the system.

PERSONNEL REQUIREMENTS

Another major advantage to Meridian is greater efficiency in field man-power usage. At the start of each work day, operations personnel view the current status of individual wells in their assigned areas. Field personnel are then dispatched to the locations that indicate a malfunction or irregularity.

This has been especially effective in the winter months during inclement weather when many well sites are impossible to access. Meridian, since the installation of the system, has been able to reduce overtime of its field personnel significantly.

Operational efficiency has also been improved with the addition of a modem and related software to the MOC that allows the MOC to be accessed by a lap-top terminal over phone lines from any location.

This capability allows Meridian personnel, with the proper access codes, to periodically check the field operations under their responsibility, and to even adjust well flow rates.

One of the unique features of the automation system in the San Juan basin is the close working relationship of Meridian, Vinson Supply, and Fisher.

Vinson maintains a duplicate MOC in its Farmington offices that receives the same data as the MOC in Meridian's Farmington production office. At 5 a.m. each day, a "Morning Report" is printed which gives the status of each well equipped with a remote operations controller.

Both Meridian and Vinson review this report, identify any problems that need attention, and through phone communications plan the day's activities.

To administer and service the nearly 200 ROC units now in the San Juan basin, Vinson has a staff of four devoted to the project. This group includes one administrative person, who handles all the purchasing of equipment and services, as well as quotations and invoicing.

An applications engineer is involved in making changes and upgrades to the system, and reconfiguring the screen formats in order to provide Meridian with requested new data on its operations.

Two full-time field technicians work closely with Meridian personnel in identifying and correcting conditions that show up on the MOC indicating a malfunction. The field people are responsible for supervising the installation of new ROCS; the movement of ROCs from one well site to another; and a myriad of field situations that require attention, such as antenna adjustments, powering up of new units, checking and replacing batteries on solar-powered units, and checking the entire system to ensure that all controls are working.

Despite the fact that there are 200 ROC units operational in the basin, and approximately four new units are being installed each week, the degree of reliability that Meridian is experiencing with the entire system is high.

During the day, Meridian updates the condition of the entire system on the hour, and Vinson makes the same check on its master station on the half-hour. In between updates, the system has a number of built in alarms that are activated at individual ROC sites and communicated to both master stations should a malfunction occur.

Meridian maintains a modem in both its Houston corporate office and its Fort Worth marketing office to receive the same production information shown on the master stations in Farmington. Fisher also has a modem in its Marshalltown, Iowa, offices to tie into the system to troubleshoot any unusual hardware or software problems.

Vinson service personnel also have personal computers in their homes to monitor the system in the evenings and on weekends.

INSTALLATION COST

The projected total number of candidate wells for automation in the San Juan basin is about 1,500. At present, the cost of a turnkey installation consisting of a remote operations controller, measurement and control elements, field wiring, and support services is from $8,000 to $18,000/well site, depending upon requirements. Where electricity is not available, the units are equipped with solar panels, which increases the initial investment.

Experience has shown that the solar-power units are quite reliable, given the number of days of sunshine that northwestern New Mexico experiences. On the rare occasions that skies are cloudy for several consecutive days, the master stations will show low battery power levels in individual solar units, indicating that batteries should be replaced.

EXPANSION PLANS

The value of the remote operations controllers to Meridian takes on added importance when one considers the size of the area, the terrain, and the extremes of weather found in the San Juan basin. More than 7,500 sq miles make up the San Juan basin, which is comprised of high mesas and deep valleys.

The weather is hot and in the summer and cold, snowy, and icy in the winter. These conditions also make communications difficult when the distance to the nearest telephone may be 10 miles or more.

As Meridian continues to drill new gas wells, each one is evaluated for installation of an ROC. Volume of gas produced, well location, and water production all enter into the decision to automate.

With the current rate of drilling, Meridian plans to have about 400 company-operated Fruitland coal wells in the San Juan basin by-the end of 1990. By late 1991 or early 1992, the company plans to have a total company-operated gross production of 500 MMcfd.

The success of the field automation system in the San Juan basin has encouraged Meridian to install similar equipment to control and monitor its gas production in the Anadarko basin of Western Oklahoma.

With a production office and master operations computer in Elk City, Okla., the company has already automated 18 well sites and has plans to automate additional wells in the near future. All of these wells will rely on solar power because of the unavailability of electricity.

Copyright 1990 Oil & Gas Journal. All Rights Reserved.