SONAN (sonic-analysis) logging resulted primarily from the research and development of a practical logging sound by McKinley et. al. of Esso Production Research Company (EPRC). McKinley primarily confined his research to the use of this system for documenting fluid flow behind cemented casing but also described the potential of this system as a flow meter. Following the publication of his findings in 1973, several service companies, including Dresser Atlas, began field testing equipment varying slightly from the EPRC designs. The variations were the result of efforts to speed up the recording of the log and to improve the ease of operations of the system and its reliability. In the time since, additional applications of this system have been noted, including its use to (1) find zones of lost circulation in drilling wells, (2) locate leak points in casing and tubing, (3) locate the source of fluid entry in uncased well bores, and (4) use this system in calculating perforation productivity profiles. McKinley also demonstrated that the data recorded could be quantitatively evaluated to determine rate of flow as well as the source. Because of the present method of data recording and the potential quantitative nature of the data, Dresser Atlas found that the processing of the field-recorded data is best performed with the aid of digital computers. Automated processing of the sound log data has been found to speed the interpretation, improve the accuracy of the interpretation and provide customers with a permanent record of our analysis for their well files. The equipment, principle of operation, several examples of the applications previously mentioned, and our processing of the data are discussed in the following pages.

A "smart" predictive computer program called RODSTAR has been developed that combines expert rod pumping knowledge with state-of- the-art wave equation and pumping unit modeling algorithms. With this computer program one can get optimized system designs in minutes by asking the program to calculate the strokes per minute, plunger size, and rod string design for a desired production rate. RODSTAR also helps the user select the pumping unit size and warns him about bad designs, pump or rods that are too big for the tubing, or pumping speed that is too high. The program's capability to automatically design steel or fiberglass rod strings ensures minimum rod loading and lowest rod string cost. In addition to the expert features of its design algorithms, the program calculates rod stresses at the top and bottom of each rod section to help avoid rod compression, and recommends prime mover size for NEMA D, gas engines, or ultra high slip motors. It also calculates prime mover energy consumption, monthly electricity bill, overall system efficiency, and the effect of prime mover speed variation and unit inertia on net gearbox torque. It can simulate full pump, fluid pound, or gas interference, and any pumping unit geometry including non-beam pumping units.

Selection of lubricants depends on many factors of design, service and operating conditions. Examples, including the selection of lubricants for pumping unit gear reducers, are given.

The increase in small diameter casing completions has increased the use of small size tubing. Gas lift would be the most suited method of artificial lift in many installations where it has not been used due to the unavailability of accurate flowing pressure gradient traverses for small conduits. Initial evaluation of gas lifting through small tubing using calculated pressure gradients based on the extrapolation of a widely accepted two-phase energy loss correlation eliminated the feasibility of gas lift. The calculated pressure gradients were much higher than actually exist. Experimental data has be gathered recently for single- and two- phase flow through small conduits. This data has been correlated into usable flowing pressure gradient traverses for small tubing and pressure loss due to friction curves for gas flow through small configurations. Two-phase flowing pressure traverses for 1- and 1-1/4-inch nominal tubing are presented for the design of continuous flow gas lift installations and prediction of maximum producing rates from wells with small tubing. Curves for gas flow are offered for calculation of the friction portion of the pressure loss is small tubing and annuli.

Major assets of producing companies include reservoirs that are subject to secondary recovery operations. These secondary projects can be improved upon through the proper application of technical knowledge and experience. During the past 10 years, large investments have been made in initiating new water-floods and gas injection projects. Improved recovery programs have been undertaken in existing secondary operations which include infill drilling, converting new or existing wells to injection service, and well workovers designed to control or improve injection profiles. With all this activity there is a definite need to monitor well and field performance to maximize both profit and recoverable hydrocarbon reserves. Today, high pressure waterflooding is relatively common. Typically, injection may exceed reservoir voidage over a prolonged period of time and even after fillup of the free gas space. Under such conditions, it is advantageous that everything possible be done to maximize oil production. Isometric diagrams and calculations can be used to pin-point candidates for large volume lift, selective well completions, and additional infill or development drilling since increased withdrawals a.re often indicated to prevent reservoir pressure from increasing unnecessarily. The use of geological isometric cross-sections in studying and monitoring secondary-recovery programs has wide application. The isometric crosssection provides a means of incorporating inherent geological parameters that materially affect all injection projects. Of primary importance is the geological interpretation presented on the isometric cross-section showing the continuity of the various layers which directly affects vertical and horizontal sweep efficiency in a secondary-recovery project. Since the unit displacement efficiency is fixed by the injection fluid selected, improvements in existing secondary-recovery projects require a better understanding and application of geological interpretive knowledge to develop practical means of improving the area1 and vertical sweep efficiency of each pattern or tract. During primary production operations, only limited geological information is required after development drilling operations are concluded. For example, isometric cross-sections could help in primary well completions. It is only during secondary recovery operations that a more detailed and reliable geological description of the reservoir is required for monitoring the progress of the flood throughout the reservoir. The need for geological definition may become quite apparent when secondary flood performance differs substantially from predictions and forecasts. Another basic use of geological data is in properly modeling the effects of stratification. This procedure is necessary in order to match reservoir performance history in reservoir simulation studies and make reliable predictions of future performance. Exotic or tertiary recovery programs will have to be selected by operators who have the necessary technology, including a better understanding of the inherent heterogeneous nature of reservoir rocks.

The use of high strength proppants in wells that are deeper than 15,000' is not new to the oil industry. Utilization of these expensive proppants; however, in shallow (+8400'), hard formation wells is new to the industry, especially in the West Texas area. Four wells in the Calvin (Dean) Field of Glasscock County, Texas are currently undergoing a comparison test. Two wells were fractured using 20/40 mesh sand while the other two wells were fractured using 20/40 mesh sintered bauxite. The justification to use bauxite in individual treatments, the preliminary results, and current well performances are discussed in this paper.

A three-well pilot horizontal well program was recently implemented at the North Central Levelland Unit (NCLU) in Cochran and Hockley counties, Texas. Short radius technology was utilized to drill two injection wells and one producer. Horizontal lateral length ranged from 500" to 700". Primary objectives of the program were to increase injection and production rates and increase waterflood sweep efficiency. Horizontal technology could also be instrumental in improving the economics of a future carbon dioxide (C02) flood. This paper discusses the theoretical reasons for drilling horizontal wells at NCLU as well as the actual drilling and completion of the wells.

This paper covers the special pumps for this condition; also some recommendations for improving gas oil separation in the well and increasing pump efficiency.

The term "long run equipment" is a flexible one and, of necessity, does not arbitrarily follow any steadfast set of specifications. This is readily understandable when consideration is given to the numerous problems involved in adapting a universal set of accessories to slow or high speed and two or four cycle engines. Also, the equipment must adapt itself to those problems peculiar to the area in which it must serve and, of course, the operators have certain preferences in regards to manufacturer or model. In the following, we will deal primarily with the equipment generally accepted and attempt to touch upon the objectives and apparent results, as well as the maintenance involved.

The single largest operating cost in the Permian Basin is electrical power due to the widespread use of waterflooding and/or high volume artificial lift. In most cases, operators with large power loads can receive preferential industrial power rates in order to lower their power costs. However, in cases where smaller power loads exist or preferential rates are not an option, the operator must investigate other options to lower its power bill. One option currently being tested is the use of natural gas-powered generators, which can generate the electrical power on-site that is necessary to run oilfield equipment using either residue or lease gas, and in turn lower your power costs significantly.

Many present and future production problems can be identified and predicted with less cost and downtime utilizing oil field chemistry applications. The chemical characteristics of drilling, completion and work-over fluids have immediate and long lasting effects that can enhance or impede production. The temperature and pressure changes that occur during production effect the chemical equilibrium of the formation fluids. The application of oil field chemistry can predict immediate and long-term chemical changes that affect production. The same chemical tests used for problem identification can be applied to maximize production during stimulation and production operations. This paper presents a review and discussion of readily available oil field chemical testing. A systematic and practical approach to interpretation and application of the results is presented. The oil field chemistry discussed in this paper includes the evaluation of chemical, microbial, and physical components in water, oil, gas, scale, and corrosion products. A water flood case history demonstrates test and results application.

This paper concerns itself with expansion of information concerning centrifugal separation equipment used in gas plants. The paper will also review basics of separation processes utilizing centrifugal force. Techniques will be described by which these and other forces combine to effect separation. It will also describe equipment proven after years of use and that has more recently been used after development efforts. Characteristics of this equipment and evaluation of results will be presented. General recommendations regarding application, use, and maintenance of equipment will be included in this report.

This paper will be concerned only with the control of paraffin through use of chemicals. The particular problems created by the paraffin deposit, or their degree of severity, will vary but will be common to certain areas of similar conditions. It is necessary, therefore, that the treating programs be flexible and adapted to the particular condition. Before such a program is designed, a complete survey of the problem should be made.

Experience has established that AC and/or DC powered electrical/electronic equipment is particularly vulnerable to damage from lightning, switching surges and other overvoltage disturbances originating on power distribution facilities! Some types of electromechanical devices are also susceptible to damage from excessive transient voltages from these sources. Overvoltages are also generated within a load complex by switching of equipment, but their magnitudes are generally lower than surges from primary distribution circuits. The application of arresters that are specifically designed for limiting surge voltages on utilization circuits has proven to be an effective means of preventing equipment damage from these common sources of exposure. Overvoltage surges such as discussed above are inherent in the operation of a power distribution network and cannot be prevented. Providing adequate protection to insure service continuity and minimize maintenance expense must be assumed by the user. AC and/or DC powered equipment is usually designed to withstand "normal" overvoltage conditions such as limited voltage variation and the surges normally experienced when energizing equipment units. This is an economical practice because protection against abnormal over-voltages can be provided for an entire installation by the application of a properly selected and installed power arrester and/or signal protector. The following sections discuss the electrical and physical properties to be taken into consideration with regard to the nature of the problem (equipment protection), proper selection of an arrester for the defined problem and installation instructions.

A systematic study was undertaken in order to establish a procedure by which the effect of operating conditions on the efficiency of beam pumping systems can be determined with a minimum of expense. The study concentrated on the effect of easily controllable parameters such as direction of rotation, counterbalance effect, motor selection, torque mode for variable torque motors, tubing back pressure, stuffing box friction and motor slip on the energy usage. The paper describes the instrumentation, data acquisition and processing system which allows accurate measurement of instantaneous motor power during a pump stroke. This measurement was correlated with dynamometer measurements in order to determine the surface system efficiency. Calculation of the downhole pump dynamometer allows determination of the effect of operating conditions on the volumetric efficiency of the pump. From these measurements, an overall efficiency can be established as a means of comparison; that is , the overall work output at the pump versus the work input at the motor.

This paper discusses the utilization of reservoir engineering data from a field operations viewpoint taking into consideration both oil and gas reservoir performance. The purpose of this discussion is to enhance the useful exchange of reservoir engineering and field data to further optimize production and monitor reservoir behavior. Attention is focused on the well rather than the reservoir. The discussion treats the question: "why collect data?" and considers conditions for proper well test data gathering and the significance of data in determining well treatments. This presentation will require two-hours of course time.

In early 2000 Hydril Advanced Composites Group introduced an alternative for standard piping products to the industry. Initially utilized for flow lines, the product, called Spoolable Carbon (Fiber) Reinforced Epoxy (SCRE), has had rapid and widespread acceptance for that application. Other applications that the product has been used for include production tubing and injection strings. Early utilization has been limited by production capacity limitations. This SCRE is a continuous length advanced composite pipe that is delivered, stored and deployed on a spool. It provides corrosion resistance to both the flowing media and the environment. Additional advantages of SCRE include an inherent resistance to fouling and pressure losses, lightweight, a reduction in the number of connections and fittings required and ease of installation. Regardless of the price of gas and oil, the driver for selecting SCRE is clearly economic. All operators are interesting in reducing both capital and operating expenditures. When considered on an installed cost basis SCRE offers significant advantages. One operator reports that the installation cost of 2-inch - 1,440 psi SCRE product is approximately 70% of the installed cost of alternative products. This paper seeks to review the development and commercial introduction of SCRE and to review, in general terms, some of the applications in an oil and gas environment that have proven successful.

In the last decade, systems analysis methods were widely used to describe the performance of flowing and gas lifted oil wells, several applications dealt also with gas wells. The present author's aim is to apply these procedures to sucker rod pumping and to develop calculations for modeling the operation of rod pumped wells. A discussion of systems analysis methodology is given first. Then, a sucker rod pumped well is analyzed and considerations are given on the application of these methods to describe the performance of a pumping system. For simplicity, wells pumping liquid only are investigated in this preliminary study. The pumping system is described by constructing System Performance Curve sheets. These sheets show pumping rates versus pump setting depth for different pumping modes. Conventional pumping units are considered and RP 11L procedures are used. After superimposing the IPR curve of the given well on the System Performance Curves, the production rates attainable with different pumping modes are easily found.

In the last decade, systems analysis methods were widely used to describe the performance of flowing and gas lifted oil wells, several applications dealt also with gas wells. The present author's aim is to apply these procedures to sucker rod pumping and to develop calculations for modeling the operation of rod pumped wells. A discussion of systems analysis methodology is given first. Then, a sucker rod pumped well is analyzed and considerations are given on the application of these methods to describe the performance of a pumping system. For simplicity, wells pumping liquid only are investigated in this preliminary study. The pumping system is described by constructing System Performance Curve sheets. These sheets show pumping rates versus pump setting depth for different pumping modes. Conventional pumping units are considered and RP 11L procedures are used. After superimposing the IPR curve of the given well on the System Performance Curves, the production rates attainable with different pumping modes are easily found.

A pressure buildup on a pumping well may be conducted by either of two methods. Direct measurement, of course, involves placing a gauge downhole. This presents special problems, however, for a pumping well. Since this procedure involves pulling the rods and pump in order to get the gauge downhole, it is usually economically infeasible. In addition, this "pulling" process introduces a new transient into the formation which adversely affects the analysis unless the well is restabilized once the gauge is downhole. The second method involves acoustically determining the depth to the gas-liquid interface, measuring the casing pressure, and calculating the downhole pressure from these two measurements. With this method, an appropriate correlation must be selected in order to correct the liquid gradient for the gas in the column. The pressure derivative is an analysis tool which has received considerable attention lately. l-6 The two primary applications of the derivative are (1) identifying the different flow regimes and (2) obtaining a unique type curve match. Since the derivative involves a point-wise pressure difference rather than the pressure rise since the start of the test, it tends to amplify even small changes. For this reason, most examples have used data that was obtained from electronic pressure gauges. The purpose of this paper is to show that the pressure derivative may be applied to acoustic data. Two examples will be presented showing (1) a well with wellbore storage and skin and (2) a fractured well.

Since the inception in 1947 of hydraulic fracturing as a method of stimulating oil and gas wells, fractured wells have become a commonplace throughout the world. This is particularly true in regions noted for low permeability and accompanying low productivity. Transient pressure test conducted in fractured reservoirs are subject to unconventional behavior which requires special interpretational skills and procedures. The purpose of this paper is to discuss those methods of pressure analysis which have been most successfully applied to wells that intersect single-plane vertical fractures. Procedures for evaluating reservoir permeability, formation damage, and fracture length are presented for both conventional and type-curve methods of analysis. Practical tests and rules-of-thumb which will help an engineer avoid common pitfalls in fractured well analysis are presented. Both infinite- and finite-conductivity fractures are discussed.

Production logs that are available to the industry today obtain a more accurate account of production; the main reason for the accuracy is that the well is logged in the dynamic production state. Interpretation of the production log is dependent upon understanding the mechanics of the well and the function of the combinations of logs used. The following approach is important in obtaining and interpreting good production logs: 1. Properly prepare the well to be logged prior to survey. 2. Have a basic knowledge of the tools used in each log. Understand the procedure, mechanics, and calculations needed. 3. Understand how to use each log 4. Learn to combine all logs so they present one overall picture of the production pattern. In recent years, the production log has mainly been applied in shallow wells (1,000 ft. to 5,000 ft.). Due to the soaring costs of drilling, successful attempts have been made to apply this technique to deeper wells. The case histories to be discussed in this paper are about deeper wells.

This paper will describe the sizing techniques for field applications using variable frequency (speed) drives (VFDs or VSDs) with electric submersible pumps (ESPs). The field installations will be described along with reservoir and production information. Then the controls available with the VSD's and their uses will be discussed. Finally the various control and transformer settings for different applications will be presented.

The average person driving down the highway past a pumping unit working away in the adjoining field has no conception of the many problems involved in the selection of this unit for its particular job and the constant continuing care that must be expended to keep it doing its assigned task year after year. All of this falls into the province of the oil business with the major responsibility on the production department of each company to keep the pumping units going and the oil coming.

High density liquid corrosion inhibitors have many advantages over conventional inhibitors in problem well treatments. High fluid level pumping wells, low pressure gas wells, high pressure gas wells, flowing wells with packers and wells with static water columns in tubing strings that have been difficult or impossible to treat with conventional inhibitors can now be treated effectively and economically with high-density liquid corrosion inhibitors. These inhibitors cut equipment costs, eliminate emulsion problems, swabbing expense, eliminate need for circulation of pumping wells, and in many cases cut frequency requirements for treatments. High density liquid corrosion inhibitors are available for both "sweet" and "sour" well fluids and for wells which produce a high percentage of water or practically no water from the formation.