Exxon Company Research Articles

The Study on 20W/40 Heavy Duty and Super-Charged Diesel Oil

Based on a lot of tests, domestic based oil and additives were chosen according to the working characteristics of heavy duty and supercharged diesel in this paper. The nyctinasty of compound additive produced by American EXXON company and domestic CD-package to based oil was inspected respectively by tests[1]. Dealing with the datum of orthogonal test by computer, the three optimum formulates of 20w/40 heavy duty and supercharged diesel oil were presented.

West Chalkley, Cameron Parish, Louisiana--A Case for Continued Exploration in Mature Producing Provinces: ABSTRACT

A potential giant gas field has been discovered in the very mature exploration province of south Louisiana, by Transco Exploration Partners (TXP) and Exxon Company U.S.A. The West Chalkley prospect is located in Cameron Parish, Louisiana, and is productive in the upper Oligocene Miogypsinoides (Miogyp) sands. This discovery is in the same producing trend as the prolific South Lake Arthur field, where the Miogyp sands have gas reserves on the order of 1.0 tcf. The West Chalkley prospect was generated by a combination of trend analysis, subsurface well control, and reflection seismic data. The feature appears to be a faulted anticline separate from the nearest production in the area, Chalkley field, which is located about 1 mi (1.6 km) to the east and was discovered in 1938. Both TXP and Exxon, working independently, recognized the potential prospect and pursued leasing activities in the area. TXP initiated discussions with the landowner in February 1988 and acquired a 960-ac (3.9-km2) lease in June. Exxon leased approximately 2100 ac (8.5 km2) surrounding the TXP lease about one month later. TXP subsequently sold the prospect to Exxon on October 12, 1988. The Exxon #1 Sweet Lake Land & Oil Company was spudded on March 16, 1989, and reached a total depth of 15,600 ft (4755 m) on July 4, 1989. Log analysis indicated a net gas pay zone of nearly 500 ft (152 m) in the 805-ft (245-m) gross productive interval. Testing through perforations near the base of the pay zone yielded flow rates as high as 21.028 MMCFGD and 330 BCPD. The well was put on production in March 1990 and has produced at rates as high as 45.4 MMCFGD and 740 BCPD. Two successful offsets have been logged, and a third is drilling. At least three more wells are scheduled, with one being a deeper pool wildcat. End_Page 27-------------------------

Analysis of compressional‐ and shear‐wave seismic data from the Prudhoe Bay field

During the last 5–10 years, there has been a considerable effort to test the use of shear‐wave seismic data in exploration. One application, which has had mixed results, is the prediction of subsurface lithology. In 1983 Exxon Production Research Company, in cooperation with Exxon Company USA, recorded compressional‐ and shear‐wave seismic data across the Prudhoe Bay field in Alaska. The survey’s primary purpose was to determine the feasibility of identifying subsurface lithology through an analysis of interval velocities and interval traveltime ratios. This case study is one example which demonstrates that it is possible to identify the gross lithology of a depositional sequence using compressional‐ and shear‐wave seismic data.

Wet gas scrubbing: State of the art in FCCU emission control

AbstractParticulates and SO2 in Fluid Catalytic Cracking Unit (FCCU) flue gas can be controlled via wet gas scrubbing. Wet Gas Scrubbers (WGS) are compatible with the gaseous emission control devices such as CO boilers or High Temperature Regeneration (HTR) now in use on FCCU's and require no changes in FCCU operating procedures. Compared with a combination of particulate control with electrostatic precipitators and SO2 control by FCCU feed desulfurization, WGS require less investment and have lower operating costs. Other advantages for WGS include higher service factor, smaller onsite plot space requirement, and simpler operation than electrostatic precipitators.Purged scrubber liquid must be treated by conventional waste water treatment technology to reduce suspended solids and COD. Even after such treatment, the purge stream will still contain dissolved solids. However, at many locations, the disposal of the purge stream can be accommodated without adverse environmental problems. Four commercial scrubbers, now in operation in Exxon Company, U.S.A. refineries, reduce particulate emissions to compliance levels with all pertinent regulations. SO2 removals are in excess of 90%. Currently, four licensee companies are also applying the Exxon scrubbing process. More are anticipated. These commercial units have accumulated over 64 years of combined operations (as of February 1, 1987).

THE OLDEST CONTINUOUSLY OPERATING REFLECTION SEISMIC CREW IN THE WORLD?

Exxon Company, USA, then Humble Oil and Refining Company, put its first seismic reflection crew in the field in 1930. Party One, renamed Party Six a few years later, never left, setting a continuous performance record for reflection crews that is believed unequalled. The history of this single party offers, in one compact package, virtually the entire story of the evolution of the reflection method’s field operations.

Development of the Guyed Tower: A Case History

Abstract Development of the guyed tower to support deepwater oil and gas production operations has been underway for about two decades. In the summer of 1983, a major milestone was reached with the installation of the first guyed tower production platform on the Lena field in the Gulf of Mexico. The authors trace the history of the development of this concept within their companies from the seed ideas in the early 1960s, through a major offshore test, to the installation of the Lena guyed tower. Possible future developments are also discussed. Introduction The installation last summer of the world's first guyed tower production platform in 1000 ft (305 m) of water in the Gulf of production platform in 1000 ft (305 m) of water in the Gulf of Mexico marked a major milestone in the development of this concept for deepwater petroleum production. The evolution of the guyed tower has been the result of the imagination, dedication and foresight of a large number of research, engineering and management personnel over two decades. personnel over two decades. Exxon Production Research Company and Exxon Company, U.S.A. have had major and continuous roles in the development of this concept. The history of guyed tower development within these companies constitutes an excellent example of the effort and time required to develop a major new offshore production system. The purpose of this paper is to outline the steps taken by these purpose of this paper is to outline the steps taken by these companies in the development of the guyed tower and to show how it evolved as the technical understanding of its characteristics and perception of its applicability improved. THE EARLY DAYS Ever since its beginnings in the late 1940s, the offshore petroleum industry has been searching for economic means of petroleum industry has been searching for economic means of developing reserves in progressively deeper waters. As water depths of interest increased, the size and cost of conventional, pilefounded steel jacket platforms (Fig. 1) increased at an pilefounded steel jacket platforms (Fig. 1) increased at an ever-greater rate. Two factors influenced this size growth:the increasing lever arm over which the environmental forces act to create moments at the base of the structure andthe tendency of the natural period of vibration of the structure to increase into the range of period of vibration of the structure to increase into the range of wave periods. Both of these factors create the need for a stiffer, wider structure and more extensive foundation if the platform is to remain rigidly based on the seafloor. It is not surprising that guyed structures have been considered for offshore use as a potential solution to this problem. These types of structures have been used for many years to resist horizontal loads with a minimum of structural material. As far back as 1894, A. W. Palmer was awarded a U.S. patent for a guyed platform for "making borings at the bottom of deep waters and in platform for "making borings at the bottom of deep waters and in tideways." In the early 1960s, an Exxon engineer proposed that cable-stayed single well conductors be used for drilling and producing in the waters off the coast of Venezuela. This was producing in the waters off the coast of Venezuela. This was basically an extension of the techniques being used in the shallower waters of Lake Maracaibo where tripod-supported wells were drilled using a derrick cantilevered from a drilling barge. By the mid-1960s, this concept had evolved into a multi-well structure held together by a lattice of trusses (Fig. 2). The wells were to be drilled from a floating rig. The only production facilities on the structure were the wellheads: flowlines would carry production to shallower water for processing. The base was supported by a bearing-type foundation called a spud can. This idea was borrowed from jackup drilling rigs. In fact, the concept was essentially a jackup leg containing wells and supported by guylines. A buoyancy can near the top was to be used to aid installation. The guying system at this time was a conventional marine mooring system using drag anchors.

RESPONSE TO THE ESSO BAYWAY OIL SPILL

ABSTRACT The 50,000 dwt tanker Esso Bayway punctured a hole in its bottom on January 28, 1979, spilling 6,500 barrels (bbl) of Light Arabian crude oil into the Neches River near Port Arthur, Texas. Oil impacted 3 miles (mi) of the river, adjacent bayous, and an environmentally sensitive salt marsh. This paper describes the response to the spill by the Exxon Company, U.S.A., Marine Department. Several contractors using a variety of cleanup methods for collection and recovery of the oil were used during the 30-day operation. The preplanned implementation of an emergency response by an Exxon team of managers, supervisors, scientists, public affairs advisors, claims agents, accountants, and communications experts to coordinate the cleanup operation is discussed. In addition to the Exxon response team, scientists from academia were retained to provide guidance in the assessment of any potential environmental impacts. The United States Coast Guard (USCG), the U.S. Environmental Protection Agency (EPA), the National Oceanic and Atmospheric Administration (NOAA), acting as the Scientific Support Coordinator, and state agencies also participated in the cleanup operation. Cleanup was completed in 4 weeks at a cost of $1.5 million with minimum private claims, insignificant environmental damage, and positive media coverage and public reaction. This paper describes the efforts that obtained these results.

OPEN VERSUS SECURE TESTING

Personnel PsychologyVolume 33, Issue 1 p. 1-2 OPEN VERSUS SECURE TESTING C. PAUL SPARKS, C. PAUL SPARKS Exxon Company, U.S.A.Search for more papers by this author C. PAUL SPARKS, C. PAUL SPARKS Exxon Company, U.S.A.Search for more papers by this author First published: March 1980 https://doi.org/10.1111/j.1744-6570.1980.tb02157.xCitations: 1AboutPDF ToolsRequest permissionExport citationAdd to favoritesTrack citation ShareShare Give accessShare full text accessShare full-text accessPlease review our Terms and Conditions of Use and check box below to share full-text version of article.I have read and accept the Wiley Online Library Terms and Conditions of UseShareable LinkUse the link below to share a full-text version of this article with your friends and colleagues. Learn more.Copy URL Share a linkShare onFacebookTwitterLinked InRedditWechat No abstract is available for this article.Citing Literature Volume33, Issue1March 1980Pages 1-2 RelatedInformation

Wheel bearing greases—performance in the laboratory and in the field

A joint paper by G. L. HARTING, of Exxon Research and Engineering Company and T. C. WILSON, Exxon Company of USA present a joint paper at the National Lubricating Grease Institute annual general meeting.

A Mechanical Model for Permafrost Thaw Subsidence

A mechanical model describing permafrost subsidence has been developed and correlated with a full scale field test performed by the Atlantic Richfield Company and Exxon Company, USA at Prudhoe Bay. The permafrost mechanical response is modeled with a linear stress-strain relation that incorporates pore pressure reduction as the subsidence loading mechanism. The pore pressure reduction is due to the phase change of pore ice upon thaw and was verified by field test measurements. The mechanical response of the well casing is included in the model with no slip assumed between casing and permafrost. The thaw subsidence model explains several features observed in the field test. The pore pressure reduction mechanism produces an upward rebound of the permafrost base, resulting in compressive casing strains above the base and tensile strains below. The pore pressure loading also produces an inward lateral motion of the thawed-frozen interface. The inward motion, together with layers of different soil types, produce the alternating compressive and tensile strains measured in the field test. These alternating strains can be significant, depending on permafrost lithology.

Resistance of Commercially Available High Strength Tubular Goods to Sulfide Stress Cracking

Laboratory tests were conducted by the Exxon Company in an effort to understand the problem of stress cracking failures of steel in sulfide environments. The primary objective was to compare the performance of commercially available API and non-API grades of tubular goods in order to determine the most economical material that can be safely used in this environment. The test procedure involved applying a cantilever load to a strip specimen having a standard V-notch surrounded by an aqueous solution of hydrogen sulfide. The concentration of the hydrogen sulfide solution was 3400 mg/1 (ppm), which is considered to be a very severe environment. All testing was conducted at room temperature. The theoretical elastic stress at the root of the notch was calcualted for each specimen. These values as well as chemical composition and mechanical test properties for 143 different heats of steel are presented. The following conclusions were drawn: (1) the upper yield strength limit for resistance to hydrogen sulfide for currently available commercial carbon-managnese-molybdenum type steels commonly used in the manufacture of oil country tubular goods is approximately 80,000 psi (550 MPa); (2) the 90,000 psi (620 MPa) yield strength AISI 4130 steel is the best of the materials tested for load carrying ability in hydrogen sulfide service; (3) on the average, other 90,000 and 95,000 psi (620 and 655 MPa) yield strength steels designated for hydrogen sulfide service do not perform as well as N-80 quenched and tempered materials; (4) modified quench-and-tempered N-80; (5) there is considerable variation in load-carrying ability of steels supplied by various manufactureres and between heats of steel from the same manufacturer; and (6) API P-110 and V-150 show the least resistance to the hydrogen sulfide environment.

Carbon-Oxygen (C/O) Log: Use and Interpretation

Where other commercial logs fail or are marginally acceptable, the C/O log should be especially valuable. It has proved a highly reliable indicator of hydrocarbon in sandstone formations, independent of formation water salinity, and usually independent of formation shaliness. Introduction A carbon-oxygen (C/O) log, which measures the carbon content of a formation and its contained fluids, has been field tested in 23 wells. The C/O ratio bas proved to be a reliable indicator of hydrocarbons in proved to be a reliable indicator of hydrocarbons in sandstone formations, independent of formation water salinity and, in most instances, independent of shaliness. The C/O log should find its primary application or are marginally acceptable. The results discussed in this paper are based on laboratory data and on more than 1,800 field measurements using the Dresser Atlas Carbon-Oxygen Log, which is patterned after one previously developed by Exxon Production Research Co. The field data were collected in Exxon Company, U.S.A., wells having known well conditions (to confirm laboratory data) and in workover wells where the predictions of the C/O log were often subsequently checked against production data. All the data resulted from 5-minute production data. All the data resulted from 5-minute stationary measurements. Using this procedure, about 20 to 40 zones can be tested in a well in an 8-hour period under normal well conditions - i.e., moderate period under normal well conditions - i.e., moderate depth and reasonably consistent lithology. This time can be reduced, as desired, by isolating the zones of interest and by ignoring intervals of known saturation. Although the commercialization of the C/O log has just begun and the eventual form of the log is still somewhat uncertain, a great deal of flexibility of operation is built into the current tool, which permits several other types of nuclear logs to be run permits several other types of nuclear logs to be run with the same instrument. In addition to the C/O log, a continuous log similar to an ordinary neutron log can be run. Also, by selective timing within the tool, gamma ray responses indicative of silicon and calcium can be recorded to aid in interpreting the C/O log in areas of unknown lithology or of mixed lithology. In a practical sense, this tool has the capability to obtain information on the hydrocarbon content and porosity of a formation, as well as to differentiate porosity of a formation, as well as to differentiate sandstone from carbonates and clean sands from limy sands. The purpose of this paper is to demonstrate the usefulness of the C/O and silicon-calcium (Si/Ca) ratios for hydrocarbon detection and to summarize field experience using these techniques. Oil Detection Using the C/O Log C/O Ratio The operation of the C/O logging tool and the physical principles upon which it relies for results have been principles upon which it relies for results have been previously reviewed in the literature. Only a few previously reviewed in the literature. Only a few comments regarding the basis for the measurement will be included here to make the remainder of the paper more comprehensible. A gamma ray spectrum, such as shown in Fig. 1, is the basic data from which the oil content of a formation is determined. These data are composed of measured gamma rays induced by high-energy neutrons in the elements oxygen, carbon, silicon, iron, and possibly other less important elements. JPT P. 1044

Drillstem-Test Assemblies for Floating Vessels

Improved drillstem-testing tools and procedures have significantly facilitated the difficult job of testing from Floating vessels. The equipment and methods described here, used successfully by one company in more than 200 tests in the Santa Barbara Channel, portend a new generation of tools for use in rough-weather areas. Introduction Drillstem testing has been used for many years to provide information that supplements electric provide information that supplements electric logging, mud logging, coring, and other formation evaluation techniques; in many cases, it provides critical data that cannot be obtained by any other method. The primary objective of drillstem testing offshore, as on land, is the acquisition of sufficient data to determine formation productivity and fluid content through the measurement of flow rates, bottom-hole pressures, and fluid properties. The mechanics involved in the testing are complicated by the motions of a floating vessel. To cope with this environment, several new tools have been developed: mudline safety valves, volume-balanced slip joints, slip-joint safety valves, and annulus-pressure-operated tester valves. The fail-safe design of these tools and the redundancy of the over-all test assemblies provide the necessary safety and reliability required offshore. The system is complex and requires the supervision of trained technical and operations personnel. Their training should include a study of the function and operation of each tool as well as of the over-all procedure. Although it would be desirable, it is not possible to detail a down-hole test assembly that would be optimum for all situations. Just as drilling procedures are tailored to meet the requirements of the well, a drillstem-test program should be designed to satisfy the information objectives, the safety considerations, and the economic realities. Besides, there is usually more than one service company available and capable of meeting these needs, and tools that have similar functions often differ in specific design and operation from company to company. The discussion that follows is based on one of the arrangements that has been successfully used by Exxon Company, U.S.A., in the Santa Barbara Channel and should explain principles applicable to floating test operations in general. Early testing of Channel formations onshore had been performed in open hole and the results were poor, both mechanically and economically. For improved reliability, the testing on the floating vessels was conducted in cased hole. Down-Hole Equipment A typical test assembly for a floating vessel is shown in Fig. 1. The bottom-hole portion consists of the following major tools (Fig. 2, from the bottom, reading up):Outside pressure recorders.Hookwall, compression set, tension release packer with integral bypass.Lower telescoping slip joints (total stroke, 12 ft, or about twice the maximum vessel heave). These permit a tester valve to operate by reciprocation without puffing tension on the packer.Reciprocal-type tester valve with sample chamber. JPT P. 851

A System for Removing and Disposing Of Produced Sand

A common problem associated with oil operations along the Gulf Coast is the production of sand. The problem is particularly acute in the prolific oil production of sand. The problem is particularly acute in the prolific oil fields of Offshore Louisiana, where the solids, when finally removed, are difficult to dispose of within existing antipollution laws. Here is the system developed by one company for removing and disposing of sand while satisfying government standards. Introduction Costly problems associated with the handling and transporting of produced solids on offshore production platforms and in pipelines leading to shore production platforms and in pipelines leading to shore facilities caused Exxon Company, U.S.A., to start an active program to develop a system for offshore disposal of sand within regulatory standards. Laboratory tests proved the effectiveness of centrifugal agitation of produced sand in the presence of a surfactant in water for removing all measurable traces of oil. A pilot unit using the principle was designed and pilot unit using the principle was designed and installed on an offshore platform to test the reliability of such a system operating under field conditions. Modification resulting from pilot test studies were incorporated into a design for a new, more reliable, less complicated permanent system. The new system was installed on the Grand Isle Block 16 L platform and on West Delta 73 A-D production complex. Both systems have been monitored for quality of discharge, and results have shown no trace of oil on the sand samples. Description of System Fig. 1 is a schematic diagram of the entire sand-handling system currently in operation. The system can be divided into three basic parts: the sand removal system, the sand transporting system, and the sand cleaning and disposal system.Sand is separated from produced fluids by conventional cyclones shown as in Fig. 1. The fluids are discharged into a surge tank, where a transfer pump moves fluid through pipelines to shore pump moves fluid through pipelines to shore facilities. Separated sand is collected in silt pots below each cyclone. (The pots are emptied into a collection trough on an adjustable, timed cycle.) Sand is forced out of the pots by differential pressure since the pots are maintained at pressures exceeding those of the collection trough. Sand is moved from the collection trough by water continuously supplied by a centrifugal pump. Sand, water, and oil move into the classifier vessel where sand falls to the bottom of the cone and free oil gravity separates to the surface for removal. The vessel pressure is controlled by an adjustable regulator that vents gas to a surge tank. A water-level control actuates a dump valve, which maintains the vessel water level as shown. An oil-level control actuates a dump valve, which empties oil to the surge tank. Water and sand move from the classifier as the dump valve opens. The stream enters the No. 1 cyclone of the sand washer. Sand is discharged into the sand washer, and the water and free oil move into the separation vessel via the cyclone overflow line. (Fig. 2 is a larger-scale schematic.) Water and oil are allowed to gravity-separate in this vessel. Water is taken from the bottom of the separation vessel to supply the recirculation pump, completing the closed loop. Water can enter and leave this loop only at the cyclone banks and at the No. 1 cyclone, respectively. JPT P. 450

A New Completion System for Surface-Controlled Subsurface Safety Valves

This system uses the annulus between concentric tubing strings for hydraulic communication. Small-diameter control lines are eliminated, thus allowing the use of surface-controlled valves in tubingless as well as in conventional completions and increasing the mechanical and pressure integrity of the system. Introduction Surface-controlled subsurface safety valves offer improved blowout protection for many wells, and U. S. Geological Survey regulations require the use of surface-controlled valves in many OCS wells. This paper describes the development and testing of one paper describes the development and testing of one type of completion system that Exxon Company, U.S.A., has adopted for the application of surface-controlled valves offshore Louisiana. Previous Industry Experience Previous Industry Experience Surface-controlled subsurface safety valves have been used in California, Cook Inlet, and overseas with excellent results.' The operation of a typical surface-controlled valve is illustrated in Fig, 1. Hydraulic control pressure inside the valve forces an operating piston downward against a spring. The downward piston downward against a spring. The downward motion of the piston causes the valve mechanism (ball, flapper, or popper) to move to the open position (Fig. 1a). When pressure is released, the spring moves the piston upward, allowing the valve mechanism to close (Fig. 1b). Control has usually been accomplished down a small-diameter hydraulic line installed in the tubing-casing annulus of a conventional completion 2 (Fig. 1c). Valves typically have been set less than 300 ft below the mud line. Development Requirements Application of surface-controlled subsurface valves to Exxon's Gulf of Mexico wells required considerable development and adaptation for sand production, paraffin deposition, and tubingless wellbores. production, paraffin deposition, and tubingless wellbores. Although valves are designed to minimize sand erosion and fouling, they still must be tested and occasionally retrieved for maintenance. Therefore, a completion system enabling low-cost valve retrieval and resetting was desirable.In wells subject to paraffin accumulation, valves may have to be set at depths as great as 3,000 ft to be below deposition. To reduce the possibility of mechanical damage when valves are set deep in directional wells and to allow for tubingless completions, it was desirable to eliminate the small hydraulic control line.The above considerations led to the evaluation and development of a completion system that uses the annulus between concentric tubing strings as the hydraulic control channel. This system allows valves to be set deep in the well, provides a high degree of reliability, and is economical to maintain. Completion System The new completion system is shown in Fig. 2. A tapered production string is swaged from 3 1/2 to 4 1/2 in. at the desired valve-setting depth. An inner string of 3 1/2 -in. tubing is run inside the 4 1/2 -in. pipe and latched at the taper point. The safety valve is pipe and latched at the taper point. The safety valve is hydraulically controlled by applying pressure to the 3 1/2- x 4 1/2-in. annulus at the surface. JPT P. 331

Spill Prevention in Offshore Petroleum Producing Facilities

ABSTRACT Blowout prevention and pollution control in offshore petroleum operations are of prime concern to Industry, Government and the public. This paper reviews spill prevention equipment and procedures used in offshore oil production and discusses Exxon Company, U.S.A. and Industry programs to achieve maximum protection. Several pollution prevention systems are utilized. Subsurface safety valves shut in the wells below the mud line if an emergency develops. Surface safety valves on each well provide automatic shut-in if an abnormal condition is detected by one of a large number of platform sensors. Oil leaks are retained in sumps. Sand erosion detectors are installed on wells to identify potential erosional failures before they can occur. The paper concludes that various Industry and regulatory programs are providing the pollution control that is needed. Technological developments and reliability improvements are continuing. Ongoing work emphasizes development of improved subsurface safety valve concepts applicable to all wells, better manufacturing quality control and standards, and future reductions of human errors through training and safety programs.

Support Programs for a Large-Scale Computer Production Control Project

Training for computer center operators, design engineers, and maintenance personnel; equipment testing to locate design deficiencies; acceptance personnel; equipment testing to locate design deficiencies; acceptance testing to insure equipment quality and to minimize installation time; and programmed preventive maintenance--these are programs that have been programmed preventive maintenance--these are programs that have been instituted by one major company to assure equipment reliability and data integrity in its computer production control system. Introduction In four of its five operating divisions, Exxon Company, U.S.A. (a Division of Exxon Corporation) has instituted a Computer Production Control (CPC) program, using identical computer centers and program, using identical computer centers and program systems to monitor and control oil and gas program systems to monitor and control oil and gas producing operations. The company presently uses producing operations. The company presently uses CPC to operate 26 fields with a total of 4,100 wells. The daily production of these fields is 315,000 bbl of oil and 1 Bcf of gas. CPC is being installed in eight additional fields, which will bring total CPC-operated production in 34 fields to about 375,000 B/D. production in 34 fields to about 375,000 B/D. The objectives of the CPC program are to increase the effectiveness of producing operations and to use manpower more efficiently. The system is designed to continuously monitor and feed back operating data to field personnel and to perform control functions, generate reports for regulatory purposes, and enter oil and gas volumes directly into the accounting system. The CPC system is a multicomponent operation, with equipment ranging in complexity from a two-position switch to a real-time process control computer. Maximum benefits can be derived from such a system only if (1) personnel responsible for the design, implementation, operation, and repair of the individual components are adequately trained; (2) measurement accuracy and reliability are verified before equipment is selected; (3) equipment is factory and field tested before it is accepted; and (4) programmed preventive maintenance is begun as soon programmed preventive maintenance is begun as soon as the system is implemented. Basic CPC Features In each division office there is a central process-control computer (Fig. 1), which is process-control computer (Fig. 1), which is programmed to monitor and direct field operations. programmed to monitor and direct field operations. The computer has a core memory of 48K and disc storage of more than 7,500K. The peripheral equipment in the computer center includes a high-speed line printer, two type-writers, and a card reader. A computer interface unit connects the computer with a communication network that links the computer with the CPC fields. Field equipment includes end devices located at the wells, metering sites, and central facilities (Fig. 2). These end devices generate volume information, measure tank levels, indicate alarms and status, and perform control functions. The field cabling connects perform control functions. The field cabling connects the end devices to the remote terminal unit, where volume information is accumulated, status/alarms are monitored, and analog (A/D) measurements are made. Upon request, this information is coded and transmitted from the remote terminal unit to the computer. The remote terminal unit also receives and decodes control and set-point (D/A) messages from the computer and transmits them to the appropriate end devices for execution. Phase shift modulation techniques are employed for transmission between the remote terminal unit and the computer interface unit. Data are transmitted at rates of 100 and 600 bits/sec. Communication between the computer center and field operating personnel is maintained through a man-machine input-output (I/O) system. JPT P. 31