Substantial economies are obtained in many areas by depleting two formations simultaneously within the same well bore. The saving in initial investment of drilling cost and equipping a dual well is forcibly evident over the costs of drilling twin wells. Present day methods for the practicable and profitable production of dually completed wells have progressed to such a degree that as a matter of practical economics operators are virtually compelled to review the possible advantages of two zone production before starting additional drilling and work-over programs.

In the 15-20 year period since most oil companies divested themselves of company-owned drilling rigs, one problem has continually arisen: that problem being training of drilling personnel within these companies to successfully supervise a drilling operation made up of an assortment of drilling contractors. Due to many varying reasons, the type and amount of supervision that these drilling contractors have required have changed with time. Most oil companies today still feel that they need to train men in drilling techniques so that they can actually go to a rig and "make hole". The opportunity for these men to gain experience in this field is usually limited due to the ever-decreasing number -of wells drilled. Consequently, the company fears the day when the last of their company drilling personnel with actual rig experience reach retirement age.

Of major importance in the efficient producing of oil is to minimize workover operations caused by wellbore equipment failures. The most frequent cause of such failures is corrosion due to the corrosivity of produced fluids. The rate of attack can increase markedly as water production increases. Unless such changes are quickly detected, corrosion-induced failures can occur before an effective inhibition program can be developed. This paper presents procedures for evaluating the corrosivity of well fluids and determining when the rate of attack changes. Also included are brief discussions on various treating procedures and how the producing characteristics of wells determine the selection of the treating method. While selection of the proper inhibitor is of equal importance in a corrosion control program, it is usually based on laboratory evaluations and is beyond the scope of this paper.

In the early days of the oil industry, producers were in the oil business. In today's oil industry, producers are in the produced water management business. The emphasis has changed primarily because the majority of the produced fluid is water. This paper will deal with one major challenge facing the oil industry today - produced water. Handling produced water is costly; however, by employing good produced water management, additional revenue can be derived. This presentation will include the following: "Evaluating Present Water Equipment," "Internal Tank Designs," "Method of Skimming," "Salable Oil," and "Treating Reclaimed Oil."

It has been said that, "Artificial lift is the most important cost item in the oil industry today." This is a quote from the Petroleum Engineer, "The Revolution in Artificial Lift" February, 1969. The development and performance of an artificial lift system designed to reduce this important cost item is discussed in this paper. This artificial lift concept conditions produced well fluids for use as power fluid in a hydraulic system for single well installations to compete with sucker rod pumping or other single well lift systems. The power fluid conditioning unit makes possible a safe and economical method of lift that is simple, flexible, reliable and compatible with automation.

One major problem frequently encountered in waterflood projects is the poor quality of produced water used for reinjection. One of the main factors usually cited for poor water quality is a high solids content. Another common problem with produced water is excessive carryover from the treating facilities , which can result in a significant loss of revenue. The produced water treatment system used at the Willard Unit near Denver City, Texas, has been successful in obtaining a good quality injection water. This paper discusses the Willard Unit treatment system and in particular emphasizes the design and operation of the dissolved gas flotation cell presently in use for oil skimming and solids removal.

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.