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This paper deals with the general principles and applications of gas lift. Various types of gas lift operations are discussed. The mechanical operations of flow valves are explained. Types of installations are analyzed. A detail design technique for the most efficient point of gas injection is outlined. Valve spacing calculations are presented. Flow valve operating pressure design is commented upon. Operational hints to increase efficiency are suggested, the closed rotative gas lift system and the future trend in retrievable gas lift equipment are mentioned.

Automatic control instruments have a great deal in common with economic principles; they deal with supply and demand. Considering that an upset in a process is a change in demand, an automatic controller must be capable of changing the supply to re-establish process balance; therefore, automatic control may be defined as balancing supply against demand over some period of time. The period of time involved in making the supply equal to the demand may vary widely, and is primarily a function of process conditions.

You have come here in the hope of learning something about the Principles of Sucker Rod Pumping. I have been studying that subject for about 20 years and I am certain that I have much yet to learn. It is quite unlikely that you will leave here knowing all that is known about that subject. Sucker rod pumping, unfortunately, is an illusion, in that it looks quite simple whereas that problems involved are extremely complicated, and little understood. And, for that reason, many things we "know" about sucker rod pumping aren't true at all.

It might be said that the fundamentals of sucker rod pumping are very simple. The plunger pump has been known for many centuries, and the mechanical and hydraulic functioning's of the modern deep well sucker rod pump are precisely the same as originally conceived. The materials and precision workmanship only have been improved.

During a pilot evaluation of a CO? water-alternating-gas (WAG) injection performed in the west Texas San Andres formation, operators discovered that CO? and water injections were being lost to a highpermeability layer in the upper portion of the formation. This problem was indicated by profile data and a lack of offset production-well responses. No offset producers indicated the presence of CO? however, CO? was discovered in an abandoned temporary injection well located 2 1/4 miles from the communicating injector.

The centrifugal pump is a dynamic pumping device. One of the limitations of centrifugal pumps is their inability to handle significant quantities of gas. Two-phase fluids with several orders of magnitude difference in the density of the phases have always been very difficult to pump. This presentation reviews the nature of gas in its relation to well production with Electrical Submersible Pumps and examines historical methods for gas handling.

Enhanced oil recovery (EOR), by gas flood, has been a successful practice since the 1930's. One of the more recent gases to be used in these operations has been C02. Large natural CO2 production from fields in New Mexico, Wyoming, Mississippi, and Colorado have begun to supply EOR projects. Naturally produced CO2 gas undergoes three major process steps before being transported, via pipeline, to the end users: production, purification, and compression. The purification step is performed to remove other gas and liquid contaminants from the C02.

A basic objective of any oil producing company is to recover the maximum amount of oil from a reservoir with a minimum cost. Many of the deep reservoirs in the West Texas- New Mexico area of production will require deep artificial lifts. The installation of any method of deep pumping is costly and operation expenses are high. Consequently, oil operators are making ever effort to reduce costs in order to obtain reasonable profits from deep pumping wells. Lower operating costs will result in higher recovery percentage of one of our most important natural resources, cure oil.

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".

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.

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.

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.

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.

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.

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.

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 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.

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.

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.

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.