Multiphase flow in pipes is defined as concurrent movement of free gases and liquids in the pipes. Flow may be in any direction. The gas and liquid may exist as a homogeneous mixture, or the liquid may be in slugs with gas displacement (which is pushing behind slugs). The liquid and gas may flow parallel to each other, or other combinations of flow patterns may be present. The gas may be flowing with two liquids (normally oil and water), and the possibility exists that the two liquids may be emulsified. The prediction of pressure gradients occurring during the simultaneous flow of gas and liquid in pipes is necessary for the proper tubing size selection, design of artificial lift installations and many other production systems in the petroleum and chemical industries. Petroleum engineers encounter multiphase flow more frequently in well tubing and flowlines. The ability to accurately and analytically predict the pressure at any point in a flow string is essential in determining optimum production string dimensions and in the design of gas-lift and other kinds of production equipment installations. This information is invaluable for predicting bottomhole pressure in flowing wells. As with any correlation, the correlations developed are often misused and applied to cases outside the range of the database from which it was developed. Even though the range of the correlation's application can be extrapolated, it must be used with caution. Hence, a decision has to be made as to which correlation should be used to suit the given set of well data. The importance of being able to assess the accuracy of calculating methods or previously developed correlations is demonstrated in this paper. In fact, their range of validation in the light of the variety of conditions is discussed. These set of tested ranges are used as tools for obtaining a criteria in order to determine the suitability of different correlations towards the given data. This paper is an extraction of work done in relation to the masters" thesis by Palisetti.

Laboratory Screening Tests are suggested to evaluate potential enhanced oil recovery projects. Standardized procedures are used to study the feasibility of (1) miscible/CO2 projects, (2) thermal processes, and (3) chemical processes. The Screening Tests are divided into four sections: crude oil characterization, injection water studies, reservoir core characterization, and displacement studies in porous media. These Screening Tests augment geologic and engineering studies and supplement (but do not replace) the more commonly known core analysis programs.

The success or failure of secondary recovery efforts is largely dependent upon the proper analysis of downhole and reservoir fluid movement characteristics, and control of these conditions to maximum displacement efficiency. The indigent reservoir reactions under secondary efforts differ dramatically from normal primary production systems. These differences generate a need for individualized analysis and correction of each problem. Many tools, materials, and techniques have evolved or have been adapted to assist with these controls; but as in all efforts, the application must suit the need lest experimentation or "trial and error" methods result in added costs that render the total economics undesirable or prohibitive. The variety of monitoring and control methods available through the service industries suggests that selective application must be made, but the tendency to assume the "single method panacea" is encouraged by individual competitive sales efforts. Problems are frequently aggravated by the misapplication of services, the least consequence being failure of the specific effort, if not irreparable damage to the project. A general awareness of the specific nature and field of limitations of these many "special services and materials is needed to aid in the selection of the proper tool or technique for the job to be done.

The widespread use of waterflooding has presented many new problems to the petroleum industry. Most of these problems are directly related to the physical process of pumping great volumes of water at high pressures into water injection wells. Until the past few years, methods of increasing or maintaining injectivity were limited to the conventional techniques of acidizing or fracturing. Within the past three or four years, however, stimulation techniques have been developed primarily for problems related directly to water injection wells. The first involves the use of sodium hypochlorite solutions followed by acid solutions to remove permeability damage caused by bacterial activity. Such activity can result in creation of large amounts of organic material and tremendous loss in permeability. The second new stimulation technique is the use of micellar dispersions. These fluids remove most of the residual oil saturation near the wellbore and greatly increase the formation permeability to water. Both new injection well stimulation methods have been widely used and have been proven highly successful. The purpose of this paper is to describe these new techniques and point out how and when they should be used. Treatment design is also discussed; case histories are presented to show the success of these types of treatments as well as to point out some of the conditions that can contribute to their unsuccessful use.

Primary separation methods (such as free water knockouts, gun barrels and skim tanks) often leave substantial amounts of oil and solids in waterflood injection water. Removing oil and solids from produced and supply water streams by secondary separation techniques such as corrugated plate inceptors (CPI) and gas flotation units can provide four benefits: 1. Increased oil sales. 2. Improved water injectivity. 3. Improved waterflood sweep efficiency. 4. Lowered injection pump discharge pressure.

Inaccuracies in hydrocarbon measurements can cause significant revenue losses for a company. This paper will discuss the problems associated with hydrocarbon measurements and the preventive measures a company can take to correct the inaccuracies. Historically, exploration and production companies have adopted a casual attitude to the necessity of accurate hydrocarbon measurements. All too often this author has heard, "Our measurements are pretty close: anyway what's a few barrels between friends". These types of attitudes can cause significant revenue losses for a company as the examples below demonstrate.

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.