NEW AUTOMATION RESTRUCTURES RESPONSIBILITIES, CUTS LEASE OPERATING COSTS

Royce W. Lubke, D. Steve Black
ARCO Oil & Gas Co.
Lafayette, La.

Automated data gathering and production monitoring in ARCO Oil & Gas Co.'s (AOGC) eastern district, in South Texas, increased operating efficiency and employee productivity.

At the beginning of each day, the production coordinator now reviews a report that shows the status of each well and facility in his area. He then schedules appropriate maintenance and repair work. As a result, field personnel are able to direct their efforts to those wells and facilities that need the most attention.

The advantages over the traditional system requiring daily on-site visits include reduced manpower needs, earlier access to needed information, and increased efficiency in setting priorities for repair and maintenance work.

The new system has been operating for almost 2 years without problems. Operating cost savings in the first year amounted to $1.1 million.

The installed cost was $1.7 million.

SOUTH TEXAS

AOGC's South Texas onshore operations area includes 271 gas wells, 32 oil wells, and 150 liquid stock tanks. Geographically, the area stretches from the Sabine River to the Rio Grande River.

The production and wells are concentrated in far South Texas, south and west of Victoria.

Before automation, AOGC relied on visual inspections to determine the status of each well and facility. The human intervention needed to collect and report production was slow. Manpower was intensive and not cost effective.

The production operation structure was very similar to that of most oil and gas companies.

An area superintendent supervised three to four production foremen. The production foreman supervised three pumpers, a three or four-man roustabout gang, and a mechanic.

On average, each production foreman looked after about 75 wells and associated central facilities. The number of wells varied depending on their proximity to each other.

The production foreman also had responsibility for overseeing new facility construction, minor recompletions, and remedial well work (see box).

On a typical day, a pumper made a minimum of one trip to each well site and facility to check operating parameters, flow measurements, tank gauges, and overall facility operations.

The pumpers found problems between the start of rounds at 7 a.m. and the end of rounds, between 1 and 2 p.m. Throughout the time period, the pumpers reported problems to the production foreman by mobile radio.

As reports came in, the production foreman set priorities and assigned work to the roustabout gang and mechanic. Occasionally, the foreman would stop work to redirect resources to a problem that needed immediate handling.

The foreman could pay overtime or call out a contract crew if redirecting the company personnel was impractical.

It is important to point out that such rescheduling was not always a result of a problem but more often a result of a problem being found during the pumper's rounds.

Pumpers collected production data by hand as they made their rounds. Unless there was a specific need, the data were not available in the district headquarters office until the following morning.

Once a week, on chart change day, everyone, including the roustabouts and mechanics, collected and changed charts. This caused disruption to normal work routines.

The charts were then express mailed to the gas data services group in Dallas. There the charts were integrated and keyed into the production allocation and reporting system (PARS).

NEW ORGANIZATION

The existing system was inefficient and costly. Production management initially wanted to automate virtually all the functions performed by the lease pumper. This would allow remote data gathering, problem identification, and control of wells and facilities.

AOGC could install such a system, but it would be expensive and complicated to use.

The limiting of automation to production reporting and problem identification functions of the lease pumper was simpler and more cost effective.

Production management recognized that this simpler automation was only part of the equation. Therefore, they also tailored the organization to the automation system.

Thus, both the system and the organization were adapted to each other to increase cost savings. This gave the production operation's organization greater flexibility in finding solutions to problems.

In the restructured organization, the positions of production foreman and lease pumper were eliminated. The responsibilities formerly handled by the production foreman were divided between a workover/construction foreman and a production coordinator (see box).

The workover/construction foreman supervises project work, while the production coordinator supervises production operations work. The new supervisors focus their attention on one set of similar problems with the same general priority. They are no longer pulled in different directions by the needs of two very different responsibilities.

Relieved of project work, production coordinators can devote the time necessary to learning the new computer skills required by the automation system. The production coordinator handles the same size area as the former production foreman, but with three to four fewer people. He has two to three roustabouts and one mechanic reporting to him.

The workover/construction foreman handles a larger area than did the production foreman.

SELECTION CRITERIA

Final system selection was based on the following criteria:

The system should provide the production coordinator the information necessary to detect problems and schedule repair work.
Information on all wells and facilities should be available at the beginning of each workday.
The system should record gas well production and related data and transmit them to a central site.
The data recorded and transmitted should directly go to the PARS system.
Continuous on-line monitoring and control of onshore wells would not be required.

Meeting these criteria would eliminate the need for daily visits to each well and facility location. With production data being recorded electronically, the need for charts and the costs associated with changing, handling, and integrating them would be eliminated.

The electronic upload of data to PARS would lessen the chance of human error in the production reporting and recording process.

THE SYSTEM

The system hardware consists of several components all of which are off-the-shelf items. The hardware items are:

Pump-off controllers (POCs)
Flow computer units (FCU) with and without expanded input/output (1/0) to monitor critical parameter
Tank level (TL) transducers
Radios
Solar power panels
Modems
IBM 286 compatible personal computers (PCs) - central collection units (CCU)
Portable calibration and collection units (PCCU).

The key pieces of equipment for gas operations are the electronic FCUs located at the wellhead, sales station, and fuel gas meter runs (Fig. 1). FCUs are gas flow measurement devices that measure pressure drop through an orifice plate similar to conventional chart recorders.

The FCU uses a microprocessor device to calculate flow rates and volume. Liquid level sensors measure the level of oil, condensate, and water in the production tanks in both oil and gas operations (Fig. 2).

Measurements from all devices are sent by radio or telephone modem to a personal computer located in the field offices (Fig. 3) and later to the Houston district office.

Most well site locations have no electricity. Therefore, standard solar cells and batteries provide power to the FCUs and communications equipment. The PCCUs are used for meter calibration, orifice plate changes, meter factor changes, and occasional data collection (Fig. 4).

At 7:05 a.m. each day, in each gas field, a polling is made.

Data the production coordinator receives from the polling include current well rates, previous day's volume downstream orifice plate pressure, and current tank liquid levels.

For comparison, 72 hr of tank level history are also reported (Fig. 5). Additional data can be reported if desired.

The production coordinator analyzes the data using field balances and comparisons to prior performance to detect the following problems:

Flow line leaks
Leaks between separator and tanks (oil and water)
Dump valve problems such as oil in the water tank and water in the oil tank
Check valve leaks
Wells loaded up or frozen up
Pressure communication in dual completed well
Communication between low, intermediate, and high-pressure gathering systems
Compressor problems, downtime, or poor performance
Measurement problems
Discharge and sales line pressure fluctuations.

The production coordinator uses the results of his analysis of the data to schedule the day's activities for the mechanic and roustabout gang.

Every second day at 7:05 a.m., the system collects data for production allocation and reporting purposes. The production allocation and reporting data upload directly into the production reporting system. Charts, chart integration, and the time loss and human errors associated with them are eliminated.

The data collection report for the production coordinator shows alarms that are useful in the diagnostic analysis of measurement parameters and operating conditions. To be of any value, these parameters must be monitored and changed as individual conditions change at each location.

Information such as occasional increases or decreases in line pressure may be seen on an alarm. These are unavailable from the snapshot created by the daily polling.

Each FCU retains 35 days of information in its memory. Data upload to a personal computer hard disk for short-term storage and use. Floppy discs or tapes provide long-term storage. AOGC stores a backup copy of the data off site as required by regulations and company policy.

In oil fields, POCs and tank level (TL) monitors work similarly to the FCUs and TL monitors in the gas fields.

The POC automatically starts and stops the unit by sensing load level changes in the pump system. This action prevents damage to the surface and downhole equipment and conserves electrical power. The system enhances AOGC's oil operation by reducing manpower, downtime, and to a lesser extent power consumption and equipment failure.

AOGC's southern district operates only 32 producing oil wells. Therefore, the overall benefits of the improved oil operations are small when compared to the gains in AOGC's gas operations. The benefits to a large scale oil production operation would be more easily quantifiable.

The new automation system required changes in AOGC's revenue accounting procedures and policy.

The gas measurement group worked with accounting and information services to write new procedures and policies.

The information services group developed the software to link the automation system to the revenue accounting. The automation system created improved operations and cost savings in the district business department. One example of this improvement is that gas volumes upload directly into PARS electronically.

Preparations are also being made to input tank run tickets from a field location via telephone modem. Manual re-entry of the gas production volumes and re-entry of the tank run volumes are no longer done.

BENEFITS

Field manpower levels have fallen 35% since start up of the automation system and reorganization. There have been no adverse effects on field operations due to the manpower reduction. Contract labor expenses dropped 36%. Vehicle mileage has been reduced by 31% and continues to trend downward. Overtime has fallen by 65%. These factors have saved $1.1 million annually in operating costs.

Payout of the initial $1.7 million investment will be slightly more than 1.5 years. In addition to savings in operating costs, field problems are identified early in the day. Wells and facilities are repaired and returned to service more quickly than in the past. The reduced downtime directly impacts current profits.

Several intangible benefits are attributable to the automation system and accompanying restructuring. Field morale has never been higher, even in the face of significant change and personnel reductions. Most field level supervisors received job position upgrades and commensurate compensation. As a result, the first level supervisors are more focused and have an increased sense of ownership.

Field level management has flourished as never before. The automation system provides real time data to operations, engineering, and marketing people in the field and in the district office. Engineers receive timely information on which to base analyses and recommendations. The gas marketers obtain data needed to optimize AOGC's direct sales and gas warranty business.

Because production data electronically upload to the AOGC production system, data for revenue recording purposes are transferred more efficiently and timely.

Costs of handling, mailing, integrating and storage of charts have also been eliminated.

The automation system simplified and quickened the finding and diagnosing of the causes of measurement errors and requested adjustments from purchasers.

Safety and environmental protection were increased because of more frequent monitoring. A secondary benefit was less downtime and lost production because of earlier leak detection.

As people have become familiar with the automation system, they have found uses for the generated information beyond what was anticipated at start-up.

KEYS TO SUCCESS

First and most important, all aspects of this project were developed in-house. The transformed operating philosophy and restructured jobs and organization were conceived by production management.

AOGC's production, facility engineering, measurement and communications groups developed and executed the system design, equipment selection, and installation.

Management members of the operations and measurement groups developed and conducted the training of the users.

A high level of employee acceptance of the new system resulted from AOGC personnel doing the entire project in-house and involving the intended users. Also, because the employees installed and started up the system, they were much better prepared to operate it than if the project had been contracted.

Second, management demonstrated a commitment and belief in the system by removing the old equipment while installing the new equipment. Everyone involved was able to see that the company was dedicated to making the new system work.

Removing the old equipment also eliminated any competition between the old and new systems and significantly increased the chance of success. The simultaneous restructuring of the organization made it difficult for people to slip back into their old ways.

Third, each function performed in the field was reviewed to determine whether it would be more economical to do it manually or automatically. A sunset review determined if some functions still needed to be done at all. The result is a system that is cost effective and simple to use and maintain.

A careful analysis of cost and complexity vs. benefits was done. As a system is made more flexible with more measurement parameters, it gains control functions. But at the same time, the system also becomes more complex.

Eventually, a point of diminishing returns is reached. The system either intimidates people so that they do not use it or people become focused on a subpart and never see the overall role of the system.

An operator must be very careful not to over automate. With a complex system the chance of failure is increased.

The combination of automation technology and a fundamental job change represents a first for AOGC's onshore production. The importance of the people who operate and maintain the system and use its output has been critical to the project's success.

Production management recognized the need for quality operating personnel and sound technical personnel with backgrounds in measurement and communications. The right people assure proper set up, operation, maintenance, and troubleshooting of the system.

The process of selecting the required people started with a review of all operation's personnel based on experience, knowledge, and potential to adapt to a new operating philosophy and system. Individuals who did not meet the criteria were reassigned, dismissed, or voluntarily withdrew as implementation progressed through training, installation, and start-up.

The district retained an elite group of personnel that had the vision to adapt and grow with change.

The authors believe that it is in the oil and gas industry's best interest to keep abreast of advancing technology in the computing, automation, and communications areas.

Industry must be willing to test the applicability to current operations and organizations. Additionally, industry needs to be open and flexible enough to alter systems and organizations to take full advantage of today's technologies.

As stated earlier, the system selection was based on requirements dictated by a new operating philosophy. Each oil and gas operator must define its own operating style and then tailor the automation and the organization to fit its needs.

ACKNOWLEDGMENTS

The authors wish to thank J. Douglas Hart and Robert Royce for assisting in the preparation of this article. Special thanks also go to Diane Armijo, David Bromley, Robert Leach, David Myers, Mike Seward, William Valerie, and Stan Wilock.