With the imminent tightening of produced water discharge limitations, oil and gas companies have focused a great deal of attention on oil-water separators. With hundreds of process systems in place and plans of many more to be constructed in the near future, designers are searching for an effective way to upgrade and/or improve traditional processes in order to meet the requirements imposed. Meeting the oil content specifications in discharge water is the goal, but the methods of obtaining this goal in the most cost effective manner will ultimately determine the project's success. Vortoil Separation Systems (VSS, a division of Conoco Specialty Products Inc.) has designed, manufactured and sold Vortoil" hydrocyclone separators since 1989. There are over 7 million bpd of installed VSS process capacity worldwide. Vortoil separators (standard, high efficiency, low pressure, etc.) provide a superior separation and operating performance to other types of separators used for produced water treatment. The significant knowledge we have gained over the past years allows VSS to offer expertise in optimizing process systems through the use of hydrocyclones. While VSS aims to make the most efficient separators available, the approach to solving separation problems is not purely to build a more efficient separator. By taking advantage of the process design options offered by Vortoil separators, system designers have solved produced water disposal problems while reducing system costs and increasing operating efficiency.

Within the last few years the progressing cavity pump has been successfully utilized as a method of deliquifying coal gas wells in the San Juan Basin. The progressing cavity pump has many advantages over other types of artificial lift. Ideally for the San Juan Basin progressing cavity pumps are capable of producing abrasive fluids at high volumes. The low profile is less obtrusive than other types of artificial lift, facilitating acceptance in the national forests. Through research, the initial problems experienced running progressing cavity pumps in the mid 1980's have been dealt with and solved therefore opening the door to an economical and effective method of producing coal gas wells in the San Juan Basin.

Progress has been made in the field of sucker-rod pumping of dual-completed wells. The evolution, resulting from field problems, in equipment and methods to pump dual wells with sucker rods will be the scope of this paper.

The flexibility of gas lift to efficiently lift a well over its lifetime is unequaled by any other means of artificial lift. With the development of a new product called the production accelerator, gas lift is now even more flexible and can efficiently produce wells that would previously have been candidates for other types of lift. The purpose of this paper is to describe how the production accelerator works and where it can be utilized to accelerate production.

The correct method of production operation often includes the use of electronic controllers with the ability to operate a well with continual monitoring of the conditions and in some cases even adjusting to the changes detected by the electronic controls. The use of such devices and the peripherals has led to a solid production increase on most wells with a reliable intermittent routine. The use of these devices has just been advanced by the advent of telemetry to a new higher level of advanced operation and monitoring. The paper will describe the various types of wells applicable to this as well as the benefits and advantages of such an application. The paper will attempt to give the various features and describe how the well is now capable of being monitored any check at any given time with just a phone call.

The cost-control procedures to be discussed were developed in the Western Division of Standard Oil Company of Texas, which is a subsidiary of Standard Oil Company of California. The Western Division operates approximately 2500 wells, located in the Permian Basin of West Texas and southeast New Mexico. Production ranges from 1300 ft pumping to 16,000 ft, flowing oil and gas. Operated oil and gas equivalent production was 132,000 BOPD in 1969 and will be approximately 145,000 BOPD in 1970. In early 1961 the cost-control system now used in the Western Division of Sotex was visualized. It could not be implemented, however, because the records necessary for control were not available. In 1963-64 this system was developed and sold to operating people with the result that the steady 10 per cent per year increase in field controllable costs was arrested. There has been no decrease in production as a result of the program. On the contrary, the Division's production has increased considerably each year without a corresponding increase in cost. With optimum producing expense as its eventual objective, the program's ultimate goal is maximum profits at all (times. Success is attributable to direct and active support by Division and District management. The system identifies areas of abnormal cost by comparing actual costs with forecast goals based on guiding standards. Comparison of actual costs vs. guides identifies the particular fields in which costs are above the forecast, tells why, and does so in time to allow corrective action.

High volume artificial lift through the use of submersible pumps has become common place in the Permian Basin. Many operators have made a significant investment with the use of submersible pumps and, therefore, it is imperative that their submersible pump program attain long runtimes, encounter limited failures, and maintain efficient oil production. To successfully operate submersible pumps, it is critical to have the capability to monitor and evaluate the overall performance on a routine basis utilizing timely, accurate data. One option is the use of Wood Group Electric Submersible Pumps, Inc.'s (WGESP) "Sub Maintenance Program", in which pertinent data is captured and presented in a format where well information can be interpreted so that proactive decisions can be made. Among the opportunities identified by the Sub Maintenance Program are production enhancements, reduction of power costs, reduction of submersible pump failures, and the proper utilization of submersible pump inventory.

Considerable savings may often be realized in optimizing production of power wells through the use of electrical workover system. Electrical workover systems group together several old and new electrical wireline through-tubing tools into a coordinated workover package, whereas conventional workover techniques are costly, requiring large rigs capable of pulling tubing and drilling. Electrical workover systems present a three-way capability for working over many wells without the danger and expense of pulling tubing and killing the well. Several workover examples are presented in this paper.

In recent years, the practice of running one or more of a variety of downhole logging tools to obtain a dynamic production profile has gained considerable acceptance. This method is particularly useful in multiple zone reservoirs where identification of productive intervals by the more conventional means of selective testing is difficult. Recently, Pan American Petroleum Corp. conducted 13 such surveys in several West Texas waterflood projects to assist in evaluation of waterflood performance. Eleven of the surveys were obtained by running the logging tools through the tubing casing annulus in wells equipped with either 5-1/2 in or 7-in. casing. Appropriate steps necessary to prepare these wells for logging tools employed. Several problems encountered during logging operations and their solutions are also discussed. Results of the surveys are reviewed along with the results of remedial work subsequently performed on two wells.

This paper is a review of the development, operation principles, application and techniques of commonly used production logging services. The surveys discussed include Temperature, Flowmeter, Radioactive and Fluid Identification logging, and combination surveys and their application to production and injection projects. Two hours of course time are required for this presentation.

Production of dually completed oil wells by various methods of artificial lift has presented ever increasing problems for the past several years. Realizing the conditions to be met and approaching them through correct design of equipment is of primary importance. The most prominent of the problems are well depths, application of surface and subsurface equipment, casing sizes and clearances in the case of parallel tubing strings. This paper deals with these and other eventualities as approached from a standpoint of tandem rod pumping.

Sucker rod and production tubing wear is an acceptable reality of oilfield operations. This wear is the result of corrosion erosion and equipment operations and contributes to between 50% and 85% of production well-service related expenses The movement of produced fluids, rods and rod couplings within the production tubing result in wear; however, there have been several new technology enhancements to substantially reduce this wear.

A valve consisting of a standing or traveling valve cage with a fixed vortex producing blades can, in conjunction with oversized valve seat and increased internal flow through capacity, augment pump efficiency while relieving some common sucker rod pump problems. The vortex valve is fitted to the barrel of the pump to form the standing valve or to the plunger to form a traveling valve. In the standing valve position there exists in every pump a restriction to entry of the oil, water, or other well fluids into the pump. The restriction is the standing valve assembly that consists of the cage, ball, and seat. All sucker rod pumps try to overcome this restriction with the vacuum that is created on the up-stroke. Another force that is at work is the formation pressure which when high can help overcome the standing valve restriction and when low offers very little assistance as is found in older pumped off formations. At present sucker rod pumps cannot be made more efficient by increasing the vacuum in the barrel of the pump. The current design of a close fit plunger moving inside a barrel creates approximately 22 inches of vacuum. If the pump manufacturers could increase this vacuum it would revolutionize pumps. Sucker rod pumps manufactured today are the best the oil patch has ever seen and probably will not change much in coming years.

In the early stages of development of any process which fills a long felt need, there may be a number of improvements or refinements of a major nature if an aggressive research program is maintained. With usage and the adaptation to more applications, the actual magnitude of possible improvements in materials becomes less and less. Stated otherwise, when a process is deemed adequate, successive increments of improvement becomes less important. Such is the case with well stimulation. It should not be implied that further research or investigation is unjustified. On the contrary, much remains to be done. As long as there are areas that do not respond properly to existing materials and techniques, there is room for improvement. The possibility of a major improvement in present processes is limited. However, there are excellent possibilities for the development of an entirely different approach to the field of well stimulation.

Paraffin and/or asphaltenes are part of the oil that is produced from all the formations in West Texas. They are stable in the untouched reservoir. but once production begins, natural and maintenance caused deposition of these oil components can occur. The deposits can reduce permeability. plug pore throats or cause changes in wettability that can drastically reduce production. This paper will cover the chemistry of the deposits, causes of deposition and removal methods. Case histories of treatments of West Texas wells will be included.

The use of electric motors as prime movers for driving oil well pumping units is well established today. In fact, reliable estimates now indicate that a sizeable majority of new oil wells going on artificial lift are being powered by electric motors. With the tremendous increase in the use of electrified oil well pumping, many operators are examining their horsepower sizing and application formulae more closely than ever in using electric motors to drive beam pumping units. Field tests, for example, generally have shown that most electrified wells are over-motored and that economy of operation, as well as lower first cost, could be realized with a proper sizing of the motor to the load. Also, there is the question of which type of motor should be selected. There is general interest in the industry today in the evaluation and advantages in the performance of various design types of oil well pumping motors.

One of the questions often asked of the ESP manufactures is "What is the maximum GOR your pump can handle?" As stated this question is impossible to answer. One of the limitations of centrifugal pumps is their inability to handle significant quantities of gas. However because of the configuration of the pump and the nature of its application, the question of its limits is extremely complex. This paper examines how the presence of free gas affects the operation of the ESP's and looks at some of the techniques used in selection of pumps for gassy wells

This paper demonstrates the application and design of vapor recovery systems and the practical aspects and increased product value realized from the use of such systems.

In recent years programmable logic controllers (PLCs) have evolved to such a point that it is often technologically desirable and more economical to apply them preferentially over hard wired relays in the small control systems typically found in oil field production facilities. This paper will provide a short history of PLC development, describe the features and capabilities of PLC"s, examine possible applications for small PLC's in oil field production operations, and illustrate several applications.

For decades the oil industry has attempted automation projects with mixed success. The mechanical nature of most electrical components and the short shelf life of first generation electronic components brought many early automation attempts to partial or total frustration. And then came the integrated circuit (IC). This microminiaturization allowed us to travel to the moon and back, to replace slide rules with light powered business-card-size calculators, to enjoy coffee brewed for us in the moments just before we awake and so on. This same technology is now at work in our watches, cars, televisions, typewriters, radios, homes and offices...touching us through nearly every aspect of work and play with reliability second to nothing that precedes it. Seeing this technology as filling a much needed gap C-E Natco has selected from the highest end of the quality spectrum a programmable logic controller (microprocessor) and coupled it with the thousands of man years of design fabrication, operation and troubleshooting experience to create hardware/software packages capable of performing the demanding tasks of a demanding industry. These systems operated LACT units, vapor recovery systems, filter plants, burner firing and shutdown systems, steam generators and a host of others...with the emphasis on reliability.

This paper will present results of a field slippage test and compare these results with laboratory testing of pump slippage presented in the 1998 Southwestern Petroleum Short Course paper. This is progress report #2, with the ultimate goal being to present an empirical equation which will accurately represent the down-hole slippage. The current results should be useful to operators for selection of clearances between metal plungers and barrels.

This paper will present results of two field slippage tests and compare these results with laboratory testing of pump slippage presented in the 1998 Southwestern Petroleum Short Course paper and field application of larger clearance pumps. This is Progress Report #3, with the ultimate goal being to present an empirical equation which will estimate the down-hole fluid slippage over a wide range of pump clearances. Utilizing the field test data an empirical equation is presented. The current results should be useful to operators for selection of clearances between metal plungers and barrels.

This paper will present the results of the last down-hole-rod-drawn pump fluid slippage testing recently completed at the Texas Tech test well (Red Raider #1). This is # 4 in the series which began with laboratory testing presented in 1998. This paper will present an update to the empirical equation which will estimate down-hole fluid slippage over a range of pump sizes, clearances and strokes per minute (SPM).

Since patenting the idea of Progressing Cavity Pumps in the early 1930's by RenC Moineau, there have been few improvements to the original design of this pump to facilitate expansion of the range of application. There have been dramatic improvements in the elastomer industry and these new elastomers have been incorporated into the stators using the original design. Recently the Geremia brothers, of southern Brazil, perfected a radical new design in this relatively "simple" technology that will allow PCP's to enter into a whole new range of performance criteria. This new design is being termed the "Metallic Stator" due the fact that much of the elastomer has been replaced with steel alloy leaving only a thin, even layer of elastomer, which is supported evenly around the inside perimeter by the base metal in the tubing. This provides the industry with numerous advantages over the conventional PCP's including: Higher pressures, lower torque"s, shorter pumps, fewer sizes, harsher environments, lower power requirements, and higher flow rates. In addition to the conventional method of driving this pump from the surface with sucker rods, this metallic stator has now been incorporated into a sucker rod free hydraulic design that can be pumped into place downhole, operated, and returned to the surface with only the use of power fluid and the proper well head valving arrangement.

Results of a field test study proved that progressive Cavity (PC) pumping systems provide greater mechanical efficiency and less electrical usage than beam and electrical submersible pumping (esp) systems in mature waterflood producing wells. These systems were evaluated in Permian Basin wells ranging from 3800 feet to 5000 feet in depth and production rates ranging from 500 barrels per day to 1000 barrel per day. Operating facilities were used to monitor production, fluid shots were used to monitor fluid levels, and inline mechanical kw-hr meters were used to measure electrical usages before and after PC pump system installations. Mechanical efficiencies were calculated based upon this data. Production tests indicate that total well productivity was increased and an incremental oil increase was realized where PC pumping systems replaced beam lift systems previously thought to be optimum. Increased water production due to waterflooding has necessitated lift revisions and beam pump optimization. When a beam lift system has reached maximum potential, a larger lift system becomes necessary. Esp systems provide increased lift capability, but at a much lower efficiency. The criteria used for selecting the test wells was maximized beam lift and economically marginal esp producing systems. The purpose for the field test was to determine if PC pumping systems were an economic alternative to lift these high WOR wells when compared to beam and esp systems. A field test study was began in 1991 to evaluate mechanical and electrical efficiencies of PC pumping systems in the environment stated above. A comparative analysis to beam and esp lift systems was then performed. This paper presents the results of that analysis and confirms that PC pumping systems are the most cost effective artificial lift systems in mature Permian Basin waterlood producing wells.