The Progressive Cavity (PC) Pump is being used in various types of applications worldwide, particularly because of its simplicity of operation and increased mechanical efficiency over other methods of artificial lift. As with all fluid lift methods, the proper selection of the pumping system's size and materials of construction is most important to ensure increased operating life and overall efficiency. The selection process for a pc pump system is relatively easy due its simple design. The down hole pump consists of only two parts: the single helix rotor and the double helix stator. See figure 1. The rotor is normally alloy steel machined to an exact tolerance and chrome plated. The stator consists of a steel tube into which an elastomer is injected and chemically bonded. The selection process involves selecting the rotor base metal with the type of plating or coating and the stator elastomer type. Included in the following text is a step-by step procedure for sizing a PC pump system including selecting: a pump model based on production rates, pressure and fluid characteristics; the rod string size and grade based on proven combined stress calculations and well conditions; the surface drive system based on the pump and rod size; and specific ancillary equipment.

Maximum production from many tight gas and shale reservoirs is obtained through high volume, high rate hydraulic fracture stimulation. The base carrier fluids for these treatments are most often shallow water wells, streams or ponds. This water is often laden with bacterial growth and saturated with dissolved oxygen requiring the fluids be treated with biocides and oxygen scavengers during the fracture stimulation to prevent accelerated corrosion of the downhole tubulars and surface separation equipment once the wells are placed on production. Unfortunately, the most commonly used biocides and oxygen scavengers either negatively react with one another or with other compounds in the fracturing fluid. This paper details the interactions and effects of various biocides and oxygen scavengers in both laboratory and field applications and presents a "best practices" for the use of these products in high volume, high rate hydraulic fracture stimulations.

In selecting gas lift equipment; there are several factors which must be given careful consideration. As each field has individual and distinct characteristics which make it different from others, these factors should be considered in the following sequences: A. Type of well B. Problems of producing the well and the overall production cost C. Problems to be considered in installation, work-over, and work-over cost D. Over-all cost of gas lift equipment and work-over on a two-year basis.

The stimulation of wells to increase the productivity has had wide acceptance in the industry in the last few years. The results have generally been beneficial, but, as in most processes, the method is not a cure-all, since in many instances the remedial operation has failed to produce the desired results. It is the responsibility of field managers and engineers, at any time, to avoid spending money on projects which will not be profitable. With limited funds available in depressed economic times, it is most important that such funds be spent on those projects with best prospects of maximum return. To aid the engineer and manager in selecting such projects, bottom-hole pressure buildup data, in many cases, have been of value. The analysis of these data is discussed using three approaches with examples of each method.

The selection of a proper application of hydraulic pumping for any set of conditions is only as accurate as the information available. The adaptability of hydraulic pumping, however, minimizes any unusual expense by wrong assumption or incorrect information. This paper will handle two phases of hydraulic pumping: the selection of size and type of installation and the analysis of various operating characteristics.

The two basic groups of pumps covered in the A.P.I. Standard 11-A are tubing and insert pumps. From these, various combinations can be made for particular well conditions by rearranging existing equipment and substituting a few fittings. A third group of pumps, which could be referred to as miscellaneous or special, use mostly standard fittings from the basic groups and are usually designed to overcome one particular difficult well condition.

In the past several years, there have been many advancements in the coating industry. The overall performance of all coatings has increased with the introduction of epoxies, urethanes and polyesters, which have better adhesion, abrasion and chemical resistance, along with increased gloss retention for high quality paints. The selection of a paint or coating system for any given situation will require certain considerations: (1) the environment, (2) degree of surface preparation, (3) economics. After all these factors have been considered, select a system that will provide the best protection and general appearance for the longest possible time, at the lowest square foot cost per year and per mil thickness applied. The most important factor in the application of coatings is the human factor. More specifically, the selection of a competent paint/coating applicator and the inspection of the paint/coating process is where the success of the job lies. And, if applied correctly, it should not fail prematurely. All paint and coatings do have a life expectancy. This paper has two objectives: (1) selection of a paint and coating contractor; (2) inspection of the coating process, including the final product. The above two objectives are related to the paint/coating of oil and gas installation facilities in the field.

Often the oil operator fails to recognize the importance of a careful study of the prime mover, yet each well that does not flow involves a problem in the selection and application of a suitable prime mover. Many formulas have been derived to determine the prime mover size. Basically, these formulas give essentially the same results when the same allowances have been made. An overall multiplier is generally applied without much thought as to the exact factors involved. Sometimes, very important factors are overlooked in obtaining an efficient, economical prime mover installation.

Presents explanations of different types of bottom-hole pumps available to produce gaseous wells. Case histories indicating increases gained by various operators with proper pump installation will be given.

Many pump designs and combinations of metals have been developed to meet the various problems (or conditions) found in an oil well. In presenting our thoughts on "The Proper Selection of an Oil Well Pump" we will, therefore, first classify the problem found in the well and then present our suggestions as to the proper design and combination of metals to be used in building the pump to meet the specific conditions of the well.

This paper discusses the primary factors to consider in the sizing of ANSI standard centrifugal pumps for production and plant applications. Practical information on selecting equipment for present and future requirements will be discussed. Material selection, mechanical seal selection, and pump modifications will be covered as part of the selection process. Explanation and calculations of NPSH and its relation to cavitation and pump sizing will be briefly mentioned. A basic overview of electric driver selection will also be touched upon.

The proper selection of an artificial lift system for a waterflood project will greatly influence the overall economics of the project. To achieve the most favorable economics, the lift system should have sufficient flexibility to handle the predicted range in producing rates, under the anticipated operating conditions, with minimum investment and operating costs. The optimum selection of a lift system depends on the design engineer's knowledge of (1) the factors which will influence the operation of the lift equipment (2) the advantages and disadvantages of the basic lift system and (3) the investment and operating costs. Two factors, common to all waterflood projects, normally considered first in the analysis of the optimum lift system are maximum anticipated fluid production and lift depth.

As the use of special fluids to complete or workover wells has become accepted practice, the number of completion and workover products on the market has increased considerably. Because of this, the selction of the fluid which will provide the best performance at the most efficient cost is a critical question. A review of the basic functions of a completion or workover fluid is presented. In addition, a discussion of the various types of completion and workover fluids is included. A decision chart is presented in order to systematize the selection process.

There have been many papers presented and many discussions about producing multiple completion wells. In fact, two papers were presented last year at the 5th Annual Short Course. We do not intend to cover the entire field of pumping multiple completion wells but must, of necessity, review some of the past history and accomplishments in this field. Dually completed wells first came into being during the early 1940s for two reasons: 1) shortage of steel (tubular goods) 2) Increased demand and price of oil. Dual completions of that day served their purpose and they also disclosed many complex problems to their operators. At that time, there were no specialized tools and practices for dual completions. The early tools were modifications of accepted tools and practices for standard single completions. Cementing techniques, while acceptable for single completions, were found to be unsatisfactory for duals as they allowed the producing pays to commingle. Imperfect packer seals were another common cause of failure.

Prior to a sound selection of injection pumps for waterflood service many factors are to be considered. With the consideration of plunger pumps versus centrifugal pumps the basic advantages of each must be carefully taken into account. When choosing one of these pumps for an individual flood project, the anticipated initial and future injection conditions for that system are of primary importance in determining the most economical type installation. Past experience with regard to initial investment and operating costs with each pump is an excellent guide toward the most advantageous decision to the operator.

API Standard 11 AX, Subsurface Pumps and Fittings, sets forth specifications covering sucker rod pumps and establishes dimension requirements to assure interchangeability of component parts. No material specifications or guidelines for the proper application of the various API pumps are given. This report was prepared by NACE Task Group T-lF-12 and is intended to serve as a supplement to API 11 AX. It presents general recommendations of metallic materials for the construction of sucker rod pumps for service in a hydrogen sulfide environment. Only pumps with one piece barrels and metal plungers are considered. The recommended materials are presented in tabular form and in a preferred order of listing for nine different environments with varying degrees of abrasion and hydrogen sulfide corrosion. The materials recommended are in common use and should perform satisfactorily when used in the specified environment. In certain circumstances other materials could also be satisfactory. The materials recommended in Tables 1, 2, and 3 and the order in which they are listed are based on the experience and judgment of the Task Group members. These recommendations are not intended to preclude the development and testing of new materials for improvement of sucker rod pump performance. Tables 4-10 list some of the materials commonly used in sucker rod pumps along with pertinent chemical and physical properties. The numbering system for the steels is from the AISI classification, the brasses are identified by numbers from the Copper and Brass Research Association, and the copper-nickel alloys carry the International Nickel Company designations. The use of specific alloy numbers should be encouraged. It is recognized that there are steels utilized in subsurface pumps with hardnesses greater than Rc 22** (valves, hard cases on barrel tubes, etc.). Experience has shown, however, that these materials give satisfactory service in the proper environment. A good chemical program is considered necessary for optimum performance of sucker rod pumping equipment in a corrosive hydrogen sulfide environment. Some corrosion inhibitors control rod breaks and tubing and flowline leaks but do not significantly affect pump life. Other corrosion inhibitors significantly increase pump life by promotion of oil wetting thus reducing friction as well as reducing rod on tubing wear, rod breaks, and tubing and flowline leaks. However, in some pump designs the inhibitor cannot reach some stagnant *areas and protective films may be removed by the rubbing action. There are chemicals used downhole that extend pump life by prevention of fouling, and still others that extend pump life by prevention of scale. Control of direct attack on pump materials, however, is best accomplished by materials selection in combination with chemical treatment.

The proper selection of metallic materials often makes the difference between a successful water injection program and an economic failure. Poor selection can often necessitate early abandonment or may limit the quantity of water injected by causing excessive shut-down time. In some floods, even a temporary stoppage of injection can cause oil to be bypassed in the formation and, if nothing worse, decrease the profit from the operation. For these reasons, much care in the selection of metallurgy throughout the water-handling operation is essential.

Care should be use in the selection and design of oil emulsion treating systems. We will discuss emulsion, how it is formed and treated, the treating systems that are used. When selecting a treating system, consideration should be given the cost of the unit, the effect of scale in the treating section, the effect of corrosion in the treating section and the corrosion effect on the treating unit itself, the use of pressure for gravity and volume control.

Selection of oil field prime movers is discussed, weighing the economic advantages and disadvantages of utilizing electric motor or gas engine drive. Selection and long term use of prime movers is presented from a "present worth" viewpoint.

In this paper, an attempt is made to present, from a practical standpoint, factors which should be considered in selecting subsurface pumps. Emphasis is given to rod-actuated equipment with discussions on special application pumps and the uses of exotic materials. Some time is spent on conditions which would dictate the use of hydraulic and submergible systems.

Experience developed in the Midcontinent Division of Exxon Co., U.S.A. indicates that well corrosion problems in rod pumped wells are directly related to the water cut of produced fluids. In general, severe corrosion problems as measured by excessive rod, pump and tubing failures, are predominant in wells that produce in excess of 30% water. Further, embrittlement and pitting resulting in reduced rod life and fatigue failures are accelerated by the presence of hydrogen sulfide in the produced fluids. Corrosion in rod pumped wells is controlled by maintaining an inhibitor film on all wellbore equipment exposed to produced fluids. The film can be formed and maintained as a well is produced by maintaining an adequate concentration of inhibitor in the produced fluids. The film can also be created by a short contact time with fluids containing a high inhibitor concentration. The film thus formed can be allowed to dissipate using frequent retreatment to maintain protection. Four methods are used to treat rod pumped wells with corrosion inhibitors: squeeze, batch flush. continuous injection, and circulation. The labor and material costs, investment, and treatment effectiveness vary with well characteristics for each method. The purpose of this paper is to present information for selecting the "best" corrosion inhibition technique for a given set of well conditions. "Best" method is defined as the most economical when both well servicing costs and corrosion inhibition expense are considered. This paper also presents formulas and guidelines for design of an effective treatment once the appropriate inhibition technique has been selected. The information presented is grouped in three main sections: (I) Selection of treatment methods; (2) Treatment design; and (3) Application of automatic chemical injectors.

The intent of this paper is to cover various types of oil field engines, their advantages and disadvantages, their rating, equipment that is available, installation features, and preventative maintenance, in order that proper selection of the prime mover may be obtained. The proper selection of a prime mover involves many factors other than the make and size of engine required. Too often only these factors are considered.

The selection of lubricated plug valves in the production field has been handled rather loosely over the years

This paper presents some stimulating ideas and thoughts on self-analysis and its effect on self improvement and self development.

The use of various separator designs, internals, and/or internal configurations can significantly enhance separation. The use of centrifugal inlet devices, in some cases, has been shown to increase vessel throughput up to eight hundred percent. Also, internal baffling and various coalescing media, including matrix plate coalescing sections and serpentine vanes, can improve the separator efficiency by eliminating short-circuiting and reducing foam. Inlet devices and vessel intemals are often used in retrofit applications to de-bottleneck facilities or simply improve performance using existing equipment. Furthermore, centrifugal separation may be utilized in vertical recycling separators and horizontal, in line recycling separators. These separators utilize tangential inlets or fixed vanes to generate centrifugal force and push the heavier liquid droplets to the vessel wall, scrubbing the gas. These technologies can be used as either