Each year more and more wells go on the pump. The Oil and Gas Journal predicts that in 1957 over 29,000 wells will be placed on artificial lift. In addition, this publication comments on a trend of a 7% increase in the number of wells put on the pump each year. The decision of whether or not to place a particular well on the pump is based entirely on the economics involved. This evaluation includes estimates of the expected production, the cost of the equipment needed, and the expected annual maintenance costs. Many of the components on a pumping unit have been studied and annual costs have been estimated, based on loads, bearing size, gear-face width, and so on. One component which has previously defied attempts at prediction of annual costs has been the V-belt drive.

The steel API sucker rod connection design used in beam and progressing cavity pumping systems has been an industry standard since the 1920"s. During these many years of continuous use, improvements have been made both large and small, yet this three part connection system is responsible for the majority of rod string connection failures. After 31/2 years of development, we now bring to the industry a new API modified four-part design with a method and system for precise make-up which expands load bearing capabilities and extends the working life of sucker rod connections. This paper describes development and testing work performed, information acquired, systems and methods created, and how the new API modified connection solves problems, eliminates or greatly extends time between failures, keeping work over and associated costs to a minimum. {See Figure - 1 }

Carbon/Oxygen (C/O) logging applicable in cased wellbores measures energy and intensity of inelastic and capture gamma rays resulting from pulsed neutron irradiation of subsurface formations. Continuous C/O logs therefore define the relative abundance of elements, such as C, 0, Si, Ca, H, etc., which in turn relates to lithology, porosity, and hydrocarbon saturation distribution in potential reservoir rocks independent of formation water salinities. Basic concepts and environmental correction will be reviewed with special emphasis being placed on practical field experiences both in sandstone and carbonate reservoirs. Such field applications include exploration for bypassed oil in old wells, location and monitoring of oil in low or unknown formation water salinities, monitoring sweep and displacement efficiency of waterfloods and EOR projects, residual oil determination, evaluation of heavy oil and tar sand reservoirs, etc.

To anyone who has been associated with the operation, selection, or purchasing of production equipment over the past 20 to 30 years, it is obvious that in the beginning oil producers made money in spite of operating equipment, and methods, rather than because of them. In the very early days of cable tool rigs, the well was drilled and pumped with the same engine, and surface equipment. Upon completion the rope, jars, and drilling bits were pulled out, and sucker rods and common barrel were installed. Very seldom, if ever, was any type of counterbalancing used. It was thought that if erratic motion of the walking beam was good enough to drill the well, then it was good enough to produce it. Of course, even with such crude and unsuitable equipment producers were able to sell of the oil they could produce at prices as high as $5.00 per barrel. Naturally they made money. With the advent of proration, deeper wells, taxes, engineers, and banks, in to the production field it became necessary that close attention be paid to the equipment used so as to produce the well efficiently. Only in this way could the loan be paid off, the taxes kept up-to-date, and a little profit left for the man who had stuck his neck out. At the present time production equipment is pattern, which has been decided upon after thorough consideration of many, many, factors affecting economics of oil production. In order to discuss new developments in pumping it is only proper to begin with the bottom hole pump because this is the item of equipment that starts the cash register ringing for the producer.

Along with the development of new tools there are continuous improvements of existing tools and techniques. It is the purpose of this paper to review some of the new radioactivity tools that have been developed and also review some of the existing tools that have undergone significant improvements. The following major subjects are discussed: The casing potential profile, the densilog, small diameter radioactivity instruments, radioactivity tracer injector, and the perforating-formation collar chart. The interpretation of radioactive tracer surveys and porosity determinations from the neuron curve will also be discussed. Because of the number of subjects covered, the explanations are brief and confined to the theory of operation, the significant improvements, results obtained and the advantages to be derived from their use.

Over 400,00 oil wells are now produced by rod drawn pumps. These vary in depths from "post holes" of less than a hundred feet to some of the deepest wells drilled, where the setting depth of the pump may be as much as 12,000 feet. The volume output of these pumps is just as varied as their setting depth. It may range from less than a barrel a day in small stripper wells to more than 2,000 barrels a day in wells where large bore pumps and high operating speeds are employed.

The costs of drilling, completing and producing oil and gas wells are continuously increasing. Therefore, the present day operator is seeking new and improved methods to more efficiently produce oil and gas. The savings available in dually completing a well are forcibly evident over the costs of drilling and completing two singly completed wells.

Progress is essential to survival. In no other industry is this more pronounced than in the oil industry. With reserves becoming harder and harder to find, we must continually strive to increase out efficiency in recovering oil from known reserves in order to maintain an adequate oil supply to meet future demands. Increasing out efficiency is important for other reasons too; one reason, perhaps closer to home, is to reduce production costs. Operating companies and service companies are constantly trying new processes and techniques, sometimes with success, sometimes without. But the knowledge gained from each attempt supplies the information which is the basis for future progress.

Dynamometers have been used for many years to analyze beam-pumped wells. The evolution from mechanical systems to modern computerized systems have provided the industry with sophisticated dynamometers for the diagnosis of wells. Typical modern systems require significant capital outlay and specialized training for proper operation; this has limited the use of dynamometers for well analysis. This illustrates a need in the industry for a simple, accurate dynamometer data-gathering tool which is easy to setup and use. This paper describes a new self-contained system which can record surface and pump cards on a well within minutes of arrival at the well. It automatically calculates inferred production based on the pump card. It also allows the operator to record valve checks, counterbalance, and perform pump leakage calculations without an on-site computer. All data can be brought to the office and transferred to a desktop computer for a more detailed analysis if needed.

The EPA announced the most sweeping changes to air and emission regulations in decades last year; several of which reach back to include all new tank batteries installed since August 2011. This talk will focus on explaining the new regulations in understandable terms, and define steps which operators can take in the field to help minimize their impact. The talk will focus on EPA Subpart OOOO, known as "Quad O" regulations, the key dates for implementation, reporting requirements, and steps necessary to take in the field.

Expanding cements have been credited with improving cement bonding to casing and formation, and for providing better Zonal isolation. Historically however, results have been inconsistent apparentiy due to misapplication and lack of meaningful job analyses. This paper discusses ditterent types of expansive cements, the mechanism of chemical expansion, and relates cement transition volume changes to the need for expansive cements. Most expansive additives depend on the presence of tricalcium aluminate (C3A) in the cement to complete the expansion reaction.' High C3A cements, due to their inherently lower quality control and erratic retarder response, generally are not preferred for most casing cementing operations. A new expansive additive has been developed which does not depend on cement to supply C3A. It can be used with any API class of cement or pozzolan-cement blend. The performance of this new additive is summarized and its limitations discussed. Case histories of selected field jobs are given, complete with cement bond logs and fracture treatment entry point evaluation surveys.

Expansive cements have been used in oilfield operations to produce better cement bonding which has been reported to help control annular flow, reduce water:oil ratios, and increase casing life by minimizing corrosion from well brines. Previously used chemical cement admixtures have been limited to bottomhole temperatures below 170F, with best results seen at lower temperatures (80 to 120_F). A new cement additive has been developed which produces significant linear expansion in laboratory tests at temperatures above 170F, with quicker expansion development seen as temperature increases. Expansion data for this cement system and field results will be presented to introduce this expansive additive.

Since the advent of hydraulic fracturing as a well stimulation tool, a variety of fluids and treatment methods have been proposed and used to improve well productivity. Fluids used in this process over the years include water, lease oil, refined oil, water-oil emulsions, acid-oil emulsions, gelled oil, gelled water, and gelled acid. A recent development has been the introduction of thick fluids with low pipe friction for hydraulic fracturing. The use of thick fluids can increase fracture conductivity by creating wider fractures, carrying larger and higher concentrations of propping agent and improving prop distribution. In many cases, the increased fracture conductivity will result in greater production increases. This paper describes the new very-thick frac fluids and low-damage fluids to improve well productivity. Early attempts to increase fracture conductivity with thick fluid were only moderately successful.- Acid-in-oil emulsions were used extensively in the 1950"s. These emulsions had excellent sand-carrying ability, but pipe frictional pressures developed during injection frequently prevented proper application for maximum productivity increase. The cost of the acid-oil emulsions was also a deterrent to widespread use as the size of treatments increased. Later, Khristianovich" renewed the interest in use of thick fluids to improve the fracturing process. The first successful application of thick frac fluids was the heavy, refined oil-water dispersions developed by Esso Production Research. These fluids fulfilled the requirements of highly viscous fluids and established new fracturing technology. Increased friction pressures generated by this type fluid are overcome by special treating techniques in which a water ring is employed between the thick oil and the pipe wall. Although this type of fracturing fluid is still used in treating specific formations, handling difficulties have reduced its overall appeal. The recently developed thick fluids described herein exhibit low friction pressure down tubular goods in addition to high viscosity in the fracture. These fluids generally provide relatively low formation damage and fracture conductivity damage. These are important factors in providing increased productivity where formation sensitivity or detrimental saturation changes are prevalent. The properties, application, and design of four new aqueous frac fluids and two new oil-based systems are described. These fluids are more expensive than conventional fluids; therefore the proper application is required.

Sucker rods connection-related failures represent today one of the main limitations of beam pumping applications. More demanding field operative conditions are pushing connections to their limits, which become thus the weakest link of the system. API Sucker Rods Specifications (11B) haven"t changed much since the 70"s. The fact that stress distribution is poor in current connection together with their tendency to get loose due to the lack of thread interference, are the main causes of stress concentration points which finally lead to failures. After several attempts to come out with a solution to address this problem, a new premium connection was developed. Lab and field tests have shown it is capable of working way over the sucker rod body capacity. Through this revolutionary change we"ve been able to expand the current beam pumping application limits. This paper will show field experience of sucker rods working under very high loads.

Polished rods have been used for more than 100 years and are the main component of sucker rod pumping worldwide. Only in the last five (5) years have manufacturers. Supply companies, and oil companies put their efforts into preventing premature polished rod failures. Even though information about polished rods was not very plentiful or available. information about polished rod liners was nonexistent. The history of polished rod liners goes back to at least 1916 where they were offered for sale by Oilwell Supply Co. The liner is designed to separate the stress from the wear on the polished rod. The polished rod liner has been completely ignored by the whole academic world. The first time a petroleum engineer learns about polished rod liners is when he goes to work in the oilfield. Almost half of the United States oil-producing areas have never understood the economical benefits of using polished rod liners and, therefore, do not use them. Hopefully, liners will be viewed with new interest when safety and environmental features are added to their money saving benefits.

A review of the performance of a 148 producing well automation project operated by remote off-lease supervisory equipment. The experimental project, initiated October 1961, is located on Gulf's Ida Hendrick "A" Lease, Keystone Field, Winkler County, Texas. Solid-state circuitry of modular design transmits and receives information over a four-wire voice frequency, telephone circuit stretching seven to nine miles between field points and area office master control. The supervisory equipment includes a tape-punch-five channel circuit for automatic data processing input. Economics is favorable and overall performance has yielded exceptional accuracy in LACT metering and tank gauging measurement.

The cementing of wells penetrating massive salt formations has posed a number of problems over the years. The fact that some cements displayed poor characteristics in saline environments, and that conventional additives were of only limited use in these same systems contributed to these problems. Other additives, designed for use in salt water, were found to provide characteristics far from the optimum while, at the same time, causing detrimental effects on other slurry properties, notably rheology, thickening time and early compressive strength. This paper describes the characteristics of new materials which provide superior performance in high-salt cement systems and illustrates, by way of field case histories, how these materials have helped improve primary cementing results in several areas.

Field performance of polymer pilot projects in North Texas, the Illinois Basin and Kansas is summarized. Although the projects represent a good cross section of reservoir characteristics and fluid properties, certain injection side changes and production responses fit a pattern. The same type of polymer was used in all cases. Extra oil, resulting from polymer treatment, is compared with the total cost of each treatment program to arrive at a cost for "Polymer Oil". To date, the four projects have produced a total of 65,100 bbl of extra "Polymer Oil" at an average cost of 29c/bbl. Ultimate "Polymer Oil" recovery is estimated at 261,000 bbl or 8.5 percent of the total oil in place at the start of secondary.

Motor shrouds and hangers are commonly used to set ESPs below well perforations in order to maximize drawdown and/or minimize gas interference. In this New Mexico gas field, conventional shroud hangers created multiple problems. Wellbore fluids and gas leaked through conventional hangers and, consequently, a new design was installed and monitored. The new positive-seal shroud:

The oilfield use of resin coating on proppant such as sand, glass beads and ceramics began in the middle 1970's. Applications include downhole use in both onshore and offshore oil and gas wells. The initial idea was to pump a partially cured or curable resin coated proppant (RCP) in frac fluid into a well and let the elevated bottom hole temperature polymerize and bond the phenolic resin particles together. These bonded particles form a downhole filter or sheet of permeable sandstone in the fracture. The earliest use was for sand control where resin coated particles were injected as a gravel pack. In 1976 the resin coated particles were first used as a small tail-in proppant in a hydraulic fracture treatment. Starting with small volumes this use gradually expanded to larger volumes until today large volumes of the frac proppant in many wells are resin coated. Resin coated materials replace both sand and ceramic proppants and have now grown to a frac market of many million pounds per year.

The oilfield use of resin coating on proppants such as sand, glass beads and ceramics began in the middle 1970's.Applications include downhole use in both onshore and offshore oil and gas wells. The initial idea was to pump a partially cured or curable resin coated proppant (RCP) in frac fluid into a well and let the elevated bottom hole temperature polymerize and bond the phenolic resin particles together. These bonded particles form a downhole filter or sheet of permeable sandstone in the fracture. The earliest use was for sand control where resin coated particles were injected as a gravel pack. In 1976 the resin coated particles were first used as a small tail-in proppant in a hydraulic fracture treatment. Starting with small volumes this use gradually expanded to larger volumes until today large volumes of the frac proppant in many wells are resin coated. Resin coated materials replace both sand and ceramic proppants and have now grown to a frac market of many million pounds per year.

The design of traditional sucker rod pump plungers has taken several approaches to reducing plunger wear with the goal of extending reciprocating lift pump run times. These methods with their advantages will be reviewed, and the concept of flushing sand and other particulates from the plunger's leading edge will be introduced by explanation of the patent-pending Sand Flush Plunger.

This paper will present and explain new equipment designed to pump gaseous wells. The need for this equipment will be explained by showing slides of pump parts damaged by wells making gaseous fluid and being over-pumped or being operated in pump-off condition. Cut away model pumps will be displayed, illustrating the application of the new equipment and its installation on existing subsurface rod pumps. The presentation will include recommendations for coping with the problems of gaseous wells.

This paper presents the development and application of new techniques for predicting the sand bank geometry created by relatively thin, non-complexed fluids in fluids in vertical fractures. The theory utilizes the concept of equilibrium velocity combined with fracturing fluid efficiency. The development includes the effects of variable fluid leakoff along the extent of the fracture face due to sand bank build-up and also the effects of the sand bank on the fluid velocity profile along the fracture face. It is found that the slope of the sand bank decreases exponentially with penetration resulting in a bank that is shaped like an airfoil. The effects on controlling stimulation parameters such as fluid pumping rate, fluid loss, and equilibrium velocity are discussed as they pertain to sand bank geometry control. Finally, the implications of the sand bank geometry on more effective stimulation design are discussed.

Progressing cavity pumps have been used on an application-limited basis throughout the world for the past twenty plus years. A vast majority of these systems are deployed in Canada and South America producing heavy, viscous oil with high sand content. Product development and numerous specialty ancillary products have most generally favored heavy oil production. A few of the ancillary products such as spin-thru rod guides, torque anchors, heavy-duty wellhead drive, etc transcend across application boundaries, however, the heavy oil market dominates most of the research and case studies. This paper will focus on P C pump product enhancement and design changes for applications that are more typically encountered by US operators. These wells can be grouped into the following: secondary recovery, light oil, high water cut, high volume, or water source wells and coal bed methane applications. These wells require a different philosophy and certainly different pump geometries than what was previously available through the manufacturers. Continuing, the paper will report on several of the products that have been developed, tested and are now being used within the Permian Basin. We will share the results of field-testing on down hole pressure sensors and a specialty rotor coating as an alternative to chrome. Benefits of new elastomers that have been brought upon the market will be examined.