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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.

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.

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.

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.

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 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.

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.

Most exotic fluids introduced into a reservoir will cause reduction in permeability near the wellbore. Dispersed water base fluids and oil base fluids create their own unique problems, such as wettability changes, and emulsions. Prior knowledge of what drilling fluids can do to a formation will, upon completion, lead to a better diagnosis of well behavior and thus resulting in more effective clean-up and stimulation procedures. Hydrochloric acid (HCL) as a stimulation fluid has been and continues to be misused as a method to increase reservoir permeability.

Artificial Lift Systems are under constant attack from storms, load and utility grid switching and internally generated switching. The associated voltage phenomena are cumulative in nature and degrade the integrity of these electric/electrical powered systems.

The importance of proper procedures, well data coordination, communications, subcontractors and employee training for submersible pump operations cannot be overstressed. This paper points out how some operating practices can result in unnecessary expense, and provides recommendations for helping to reduce these costly mistakes. It is felt that if these recommendations are followed, it will result in highly successful submersible operations for the user.

Attent ion to proven des ign parameters, such as are used to design plant process equipment, can improve the operation of petroleum production systems. A review of the development of primary extraction devices is given, along with formulae for efficiency and allowable velocities. Vane type, wire mesh and centrifugal are examined. Staggered baffles and zig-zag or wave plates are discussed. Design criteria for the application of these primary elements are compared, thus allowing the selection of the optimum type mist extractor for most desired services.

Indiscriminate selection of production logging tools through haste or lack of knowledge has often resulted in inadequate or incomplete information on down-hole fluid movement. With the proper selection of tools through knowledge of both tools and well problems, more information can be obtained. A comparison of tools and methods is presented providing procedures which can be utilized for optimum analysis of down-hole fluid movement.

Proper cleanout of millscale and other iron oxides from new tubular goods prior to their use reduces production damage by deposition (in the producing formation) of iron solids and iron in solution. Iron removed from new tubulars by stimulation fluids has caused formation damage and reduced production for many decades. This iron is available for removal from the walls of the casing and tubing by the action of stimulation acids and erosive proppants being pumped to stimulate the well. The sources of this iron are listed below. 1.

In the early stages of production of oil in the Pennsylvania and West Virginia fields, very little, if any, "bad oil" or emulsions were found. The small amount that was made created a very minor problem. The reason for this small amount of emulsion was due to the fact that oil produced in these fields was almost void of any foreign matter. Also, what water was produced was almost pure and very little gas was found. This kind of condition will not make an emulsion. This will be explained later.

A discussion of the properties and sensitivities of high strength tubular goods outlining selection and handling criteria which must be followed to assure satisfactory performance. High strength correspondingly reduces ductility of these steels causing them to be particularly susceptible to defects and corrosion.

During the past several years, production and service companies have been trying to solve an old problem that occurs after fracture of productive zones in the Permian Basin. Many solutions have been used with little or no success to prevent proppant flowback. The problem of proppant flowback occurs in both cased hole as well as open hole completions. New applications using old completion technology have been applied recently to improve control of proppant flowback. The technology used was developed from sand control methods dating back to the 1g70 t s.

There are many types of proppants and mesh sizes to consider in the design of a fracture stimulation treatment. When considering proppants, sand (Ottawa, Texas Mining, Unisil), bauxite, intermediate strength proppants (ISP), resin-coated sand (RCS), precured resin-coated sand (PRCS) and Z-prop, the principal questions seem to be, "Which one do I select and how should I use it?" Maximizing adequate long-term productivity in low-permeability reservoirs is dependent on both fracture penetration and fracture, conductivity.

For worthwhile oil or gas well stimulation the best proppant and fluids have to be combined with a good design plan and the right equipment. Proppant selection is one of the important areas which determines how worthwhile and how successful the stimulation treatment can be. To select the best proppant for each well a general understanding of available proppants is imperative. Also, the latest proppant properties for design are taken at downhole conditions with embedment, temperature, crushing and long term effects all being considered.