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This paper was prepared for the 43rd Annual California Regional Meeting of the Society of Petroleum Engineers of AIME to be held in Bakersfield, Calif., Nov. 8–10, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The Kern River Field is a large, shallow, low-gravity oilfield five miles northeast of Bakersfield, California. With the expansion of thermal recovery operations in the Kern River Field, Getty Oil Company (at that time, Tidewater Oil Company) realized that a method had to be devised to obtain more frequent and more precise well tests. The resultant Kern River SCAN System was placed in full operation in October, 1969. After three years of operation, the overall theory and design is unchanged. Data reports, maintenance procedures, and validity techniques have developed as operations deemed them necessary. It is safe to say that SCAN is the largest and most successful oilfield automation system in existence. Besides gathering a large volume of information, SCAN is constantly evaluating this information and, in some cases, making preliminary decisions. The basic function of the SCAN system is to monitor gauging operations, production status and injection status of 2,636 producing wells and the operating rates of 129 steam generators. This report explains the configuration of the central computer, the peripheral devices, the telemetry system and the end devices. Maintenance and reliability of the various components are discussed. The SCAN software developed from the original operating and report programs and is now supplemented by many FORTRAN programs developed in-house. Report output from SCAN is used by field personnel to monitor daily operations and by engineering and technical personnel to evaluate well performance. personnel to evaluate well performance. increases in operating efficiency are shown in the report. Introduction Getty Oil Company's secondary recovery operation in the Kern River oilfield is well known as the largest and one of the more successful of enhanced oil recovery operations due to steam injection. To increase efficiency of the large thermal operation, a computer-controlled automation system was installed in 1969 to monitor production and injection volumes. This automation system was developed by CAE Electronics, Ltd., of Canada and is named SCAN, an acronym for sample, control, and alarm network. The system consists of a completely devoted central computer that monitors 96 field sites. The field sites are named AWT'S, for their main function is automatic well testing. The production of the more than 2,600 producing wells is gathered and tested at these AWT sites. The operating rates of the 129 steam generators are also collected at the nearest AWT site.

This paper was prepared for the 43rd Annual California Regional Meeting of the Society of Petroleum Engineers of AIME to be held in Bakersfield, Calif., Nov. 8–10, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Chanslor-Western Oil and Development Company's Production System Monitor, PSYMON is a computer-directed well test system which became operational in January 1971 and now monitors about 20,000 bbls of produced crude per day from over 700 cyclic steam, steam drive and insitu producing wells in the North Midway-Sunset Field. PSYMON was built around existing field hardware which was developed between 1964 and 1970 as a manually operated system that includes centralization of produced fluid handling, fluid metering and BS and W measuring equipment, and electromechanical device control. These end-device centers called Remote Field sites are controlled by an electronics system which utilizes audio-tone serialized communications between a central mini-computer control unit and a number of Remote Field Units containing the memory and logic necessary to perform well tests on a selective basis. Due to modular design the system is easy to maintain and expand and can handle virtually any conceivable end device. Because it is organized with remote memory the system is asynchronous and can tolerate intermittent communications failure without loss of field data. A unique feature in this system is a manual control unit which can duplicate any computer command and also transmit other commands used in Remote Field Unit troubleshooting. Normal reporting and control are via teletype. PSYMON has operated for over one year with a high degree of reliability and good accuracy. The total investment was modest and will be easily returned by the decreased operating cost and increased production which has been evidenced during the first years operation. The system is considered a success and will be expanded as economics dictate. Introduction Over the past eight years Chanslor-Western Oil and Development Company, an independent oil producer owned by Santa Fe Industries, has producer owned by Santa Fe Industries, has operated one of the most successful cyclic steam projects in the San Joaquin Valley at North projects in the San Joaquin Valley at North Midway-Sunset and their move to computer production control evolved as a result of their proven production control evolved as a result of their proven well-by-well approach to thermal recovery project analysis. Originally developed as a well project analysis. Originally developed as a well test system, the Production System Monitor, PSYMON, is now potentially expandable in size PSYMON, is now potentially expandable in size and function to whatever degree necessary to meet the needs of the future as oil recovery techniques and associated hardware become more sophisticated.

To maintain operational automated systems we as and oil field contractor are confronted with many varied problems. The installation and maintenance of these systems are varied and each individual problem could not be discussed. The basis for this paper will be derived from actual invoices of maintenance performed on automatic tank batteries, production test equipment, waterflood stations, electrified injection and production headers, computerized operations, and LACT installations. It is believed that this information along with cooperation with manufacturers and producers there will be a reduction in down time, installation cost, and maintenance costs. The tabulated data in this technical paper will give us a starting point to eliminate the problems which are the most costly. Many of these procedures are being incorporated by some of the manufacturers, but as of this time not one has utilized the latest advances of electronics to facilitate a completely smooth automated system. For the purpose of this paper allied components will consist of switches, relays, contact closures, and valve operators or solenoids not mounted within the panel or control system operator. Panel components will be those items located within the panel itself, which is usually located on the skid or mounted very close to the above system. The following data was taken from all automated systems, but they are representative in cost and percentage to any installation.

This paper was prepared for presentation at the 47th Annual Fall Meeting of the Society of Petroleum Engineers held in San Antonio, Tex., Oct. 8–11, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by who the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The use of a computerized automation system in the production of oil and gas fields can be an effective means of maintaining high producing rates at a low operating cost. This is borne out by experience in several existing projects. As technology advances it is very important to be aware of new approaches that can be applied in the field and consider these approaches when evaluating a potential automation system. This paper discusses some of the new approaches as it paper discusses some of the new approaches as it relates to the measurement of gas flow rates and net-oil values. Introduction Since 1966, Amoco Production Co. has installed computer automation systems in many of its major fields. The systems were designed to effectively and economically operate the fields using the latest available technology. Although the systems vary in design and operating philosophies, each one is designed to maintain a philosophies, each one is designed to maintain a maximum production rate at a minimum operating cost. Each project is designed with a certain amount of standardization; however, where advances in technology offer economical improvements over existing projects the latest technology is employed. Two specific areas of advances in technology involve gas flow and net-oil measurements and calculations. Several schemes have been used to obtain these values in projects in Wyoming and Texas. Rather than projects in Wyoming and Texas. Rather than standardize on one scheme, the procedure that most economically adapts to the specific automation project is employed. As of the first of 1972, Amoco has developed a considerable amount of operating data on four computer automation projects that will be of great benefit in the design of future installations. Only a brief summary is presented on the Elk Basin and East Texas presented on the Elk Basin and East Texas automation systems as these projects have been reported in other publications. The Smyer project in West Texas, which was installed in project in West Texas, which was installed in 1969, is related because of the significant production increase obtained as a result of production increase obtained as a result of automation. In the Hastings Field installation new concepts in gas flow and net-oil measurement calculations were pursued to reduce the total project cost. ELK BASIN In April, 1966, Amoco Production Co. (then known as Pan American Petroleum Corp.) installed its first computerized oilfield automation project in the Elk Basin field, Wyo.). At project in the Elk Basin field, Wyo.). At the time this system was put into operation it represented the latest thinking available in the industry.

Graham, O.W., Instruments, Inc., a Division of National Tank Co., Tulsa, Okla. Publication Rights Reserved This paper is to be presented at the Mechanical Engineering Aspects of Drilling Production Symposium in Fort Worth, Tex., on March 23–24, 1964, and is considered the property of Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Engineers or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. In the past few years there has been a continuous barrage of information concerning the very latest developments in the field of solid state electronics. Anything associated with the field of electronics has had a certain amount of romance added to its colorful career which began in the early 40's. In 1950 the oil companies began a program of automating the production of oil [Fig. 1]. A very intensive program was undertaken by one company in the Hobbs, New Mex., area and after a considerable amount of time had elapsed the indications were that the automating of an oil field could be accomplished and a proven payout made. Now comes the automation of gas fields. Until recently the production of gas from wells in a given field was controlled manually, and in a few rare cases a direct wire system was employed where 110 V or 440 V was used to operate an electric motor which in turn changed the air supply to a diaphragm actuated choke for changing the flow rates at a remote point. It is now desirable that a more sophisticated system of well control be used for many reasons. One, where the distance between the control station and the well is of considerable length, the cost of the multiconductor wiring to deliver the voltage to the motor in the field becomes quite expensive. So, then it is desirable that small wire, or microwave, or radio equipment be used to transmit signals to the distance points. To do this, a different method had to be developed [Figs 2 - 5]. We, in the manufacturing business, realize that a system must be developed that is reliable and as service-free as possible. One of the costs that the producing companies continued to overlook during the period of time they are estimating the cost of equipment and the payout period is the need for preventive maintenance and repairs. On a recent trip to Louisiana I visited approximately 15 installations of automation equipment and at every location there was some difficulty with the equipment and, in every case except one, the oil company had no one in the area that could perform, the repairs on the equipment, even though some of it had been in three and four years. No equipment manufacturer to date has the capability of manufacturing equipment to operate unattended without maintenance for extended periods of time. The oil companies and gas companies are going to have to take upon themselves the responsibility of seeing that an educational program is undertaken to develop people in their own organization to maintain complex electronic systems [Fig. 6]. Either that or they are going to have to be willing to pay for outside companies to perform this service.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Amoco's position in West Texas is rather unique in that we have a high concentration of wells in a relatively small geographical area. This situation caused us to take a different approach to automation from any other in the producing industry that we know of today. Amoco's operations in West Texas include four Area offices and about 5,000 producing and water injection wells which are prime producing and water injection wells which are prime candidates for computerized automation. The basis for our approach to automation in West Texas was developed from information learned from a pilot project in the Smyer Field in Hockley County, Texas. This pilot project was designed to test all applications which reasonably offered an opportunity to reduce labor or accelerate production. As a result of this pilot, we decided that future Amoco operated automation projects in West Texas would be based around the following concepts:Pumpoff Control of Beam Pumped WellsAutomatic Well TestingData GatheringAlarm Monitoring These basic concepts permitted developing modular standard software applicable to all West Texas projects. projects. Once the basic concept for automation in West Texas was established, it was then necessary to develop an optimum computer system for this large number of wells. Economics and other advantages dictated that a Master-Mini, two level, hierarchical computer system would be best. The plan established for automation in West Texas included running multi-conductor cable to each producing well for pumpoff control and monitoring various statuses. It soon became evident that with conventional telemetry equipment available at that time, cabling costs would approach $1,100 to $1,200 per well and would be prohibitive. The obvious way to reduce cabling costs was to increase the number of RTU's which would in turn reduce cabling costs. We finally interested one telemetry vendor in designing and developing a small RTU referred to as a Mini RTU. We believe this was the first telemetry gear actually designed primarily to meet the requirements of oilfield automation.

American Institute of Mining, Metallurgical and Petroleum Engineers, Inc. This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Application of a "systems concept" to the drilling operation is discussed in this paper. Through the use of hydraulics, electrical systems, electronics and a new approach in basic design, automation of oilwell drilling has been accomplished. The basic functions of the machine are described and methods of control are presented in simplified form. Automation will permit an increase in the application of engineering to drilling operations through the use of computer control. Downhole variables can be adjusted for optimum drilling rates; safety features can be incorporated in the controls to minimize downhole hazards while tripping; and vast amounts of data can be accumulated since all machine functions are continually monitored electrically. Rig safety should be greatly improved due to the remote operating position of the crew. It is concluded, that through automation, economics of oilwell drilling will improve due to lower moving costs, improved safety, increased efficiency and better working conditions which will upgrade personnel. Introduction Any repetitive operation, such as the making and breaking of drill string connections when tripping or adding joints of pipe when drilling, lends itself to automation. Economics within the drilling industry have prevented, until now, the development of an automatic machine to perform drilling functions. Domestic land drilling has seen the exodus of most of its qualified personnel to offshore, foreign drilling and more desirable industries with better working conditions. Cheap equipment through cannibalization and auctions, has helped the remaining contractors to stay in business with no earnings from which to modernize. While replenishing their rigs from the vast reservoirs of used equipment they could not correct the economic pressures brought about by reduced demand. These same pressures forced personnel from the industry. While the land contractors were retrenching, foreign and offshore drilling experienced a record growth.

This paper was prepared for the 44th Annual Fall Meeting of the of the Society of Petroleum Engineers of AIME, to be held in Denver, Colo., Sept. 28-Oct. 1, 1969. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Production in the 80 year old Salt Creek Field, Natrona County, Wyoming has greatly increased through waterflooding and technological advances. Facilities installed from 1910 to 1930 to handle 40,000 barrels of fluid per day were modernized to handle ten times that amount. To design an effective, yet low cost, system of this magnitude posed many problems. Simplicity of posed many problems. Simplicity of design was a keynote from the beginning. Major field revisions began in 1958. A manifolded flowline system was installed from 1963 through 1968 which connected 1,000 wells to 16 automatic custody transfer stations. An automatic well test and well monitoring system is now being installed at a cost of $671,000. Initial data indicates that the automation project will pay out in 4.7 years. project will pay out in 4.7 years. Guidelines for the modernization and automation of the Salt Creek Field are presented. The equipment design, procedural and organizational changes, procedural and organizational changes, and economics of the automation system are reviewed. Introduction The Salt Creek Field, with nine producing formations, is located forty producing formations, is located forty miles north of Casper, Wyoming. The nine by five mile structure is on the southwestern flank of the Powder River Basin. Pan American Petroleum Corporation is contract operator for the Light Oil Unit (LOU), or northern two-thirds of the field. Consolidation and modernization of battery and flowline installations began in 1958. Most of the field system from the well head to the pipeline sales point was replaced. The pipeline sales point was replaced. The new facilities provide for partially automated operation, have high capacity, operate inexpensively and will handle secondary recovery needs of the present and future. Currently, Pan American is installing automation facilities which provide remote well status monitoring and well testing of 1,000 producing wells. producing wells. A case history review of field modernization and automation is presented. Equipment, method of utilization, operating problems and economics of a field-wide problems and economics of a field-wide monitoring and testing system is discussed.

ABSTRACT A primary tradeoff in the design of a vessel dynamic positioning system is tightness of control versus the modulation levels of the automatically controlled propulsion units due to wave motion and noise. An algorithm is described whereby the parameters of the digital controller are adjusted to achieve the desired compromise between control stiffness and thruster modulation, while maintaining the vessel stability margins at their design values. The algorithm is currently implemented in the DP system of a new North Sea drill ship, Nordic Off shore?s Havdrill. As presently mechanized, the algorithm must be adjusted by an operator to respond to changing environmental conditions. However, a scheme is discussed through which the controller would automatically adapt to changing weather and maintain thrust modulation within desired levels. The basic algorithm is applicable to any existing vessel dynamic positioning system which utilizes a digital computer for control. Different degrees of automation are achievable to meet operator requirements for monitor and adjustment of control stiffness or thruster modulation. This permits the operator to quickly change and update the tradeoff to meet changing requirements without altering the basic stability of the positioning system. Analytical results, have been verified through simulation. These study results, including computer data, are presented in the paper. Also included are the results of Sea Trials and their comparison with analytic and simulation results. The inclusion of such an algorithm in the controller of a vessel dynamic-positioning system permits a rapid, reliable adjustment of controller operating characteristics? with the confidence that the basic stability of the system will remain unchanged. INTRODUCTION A primary requirement in the design of a DP control system is that modulation of thrusters and power generators be maintained within tolerable limits. These limits relate to the amount of reserve power which must be generated, fuel consumption, and to thruster and generator equipment wear-out rates. This requirement must be satisfied over a widerange of weather and sea state conditions. If the DP controller design is exclusively oriented toward the satisfaction of these modulation limit's under worst case environmental conditions, over-all control system tightness and holding accuracy may be compromised. It therefore becomes desirable to permit on-board adjustment of DP controller parameters to achieve the maximum control system positioning accuracy consistent with thrust modulation limits. This adjustment can be performed automatically through an adaptive control scheme which responds to changes in varying weather condition, while permitting operator override to update modulation limits as desired CONTROLLER DESIGN APPROACH The synthesis of controller gain and filter parameters in the design of the computer software essentially involves a tradeoff between the required tightness of the dynamic positioning control system and the acceptable thrust modulation levels imposed by both the power generation system anc1by the thrusters themselves. The required control tightness is, of course, dictated by the station keeping position accuracy, or "watch circle," requirement for the given environmental design criteria, i.e., wind, waves, and current.

Abstract The New Mexico Manual for the Installation and Operation or Commingling Facilities was formulated by an industry study committee appointed by the Oil Conservation Commission. To those reading the manual for the first time, the requirements might seem quite stringent. Without the manual, however, there would probably be no new commingling installations approved by the Oil Commission in New Mexico today. This paper briefly explains the thinking behind some or the more controversial requirements or the commingling manual and emphasizes the impetus added to automation through the privilege or commingling. It might be added that the Federal Petroleum Board and a number or State regulatory bodies were interested in the Committee's study and requested copies or the final manual. Introduction In April, 1961, the New Mexico Oil Conservation Commission issued a memorandum which indicated that commingling abuses were probably occurring. To this end the Commission appointed an Industry Study Committee, comprising 11 producer representatives and two Commission members, to propose installations which would be as "foolproof" as possible. The Committee soon realized, however, that the design or a completely "foolproof" system would be impossible. Then primary consideration was given to the design of systems which would minimize failures or accidental mismeasurements and which would facilitate detection of purposeful mismeasurement. As a result or this work, the New Mexico Oil Conservation Commission issued Order No. 2060 which makes available administrative procedures for two types of commingling, i.e., [1) where two or more zones underlying a single basic lease and having identical ownership are commingled into a common tank battery, and [2) commingling production from the same zone underlying two or more leases [with diversified ownership] into a common tank battery. Exception to both Rule 503 [zone segregation] and Rule 309 [lease segregation] can also be obtained for two zones underlying two different leases. GENERAL COMINGLING RULES The Manual for the Installation and Operation of Commingling Facilities issued by the Commission outlines minimum standards which must be met for an installation to be eligible for administrative approval. While the various types of commingling installations may differ in design as well as operational procedure, certain basic rules apply to all installations. The following paragraphs contain comments or explanations of the general rules. When wet oil commingling, it may be necessary to use the previous month's BS and w content to estimate the net oil production in order to stay within the assigned monthly lease or zone allowable, subject to the daily and monthly allowable tolerances permitted by the Commission. This will be particularly true when metering large volumes of water prior to dehydration. The general rules also state that data such as meter readings, meter factor, per cent BS AND W, etc. shall be submitted with the monthly production report to the State or as an alternate retained on the lease for at least two years. Since this is obviously for auditing purposes, it would be hoove each operator and/or pumper to maintain clear and concise production records. It might even be prudent to note the meter serial number even though this is not required. An allocation formula was provided merely to proportion differences between the system production and the summation of the individual zone or lease meter readings. Some discrepancies, although small, will be inherent in most all commingling systems.