An effective corrosion-control program depends upon well conditions (fluid levels, gas blowing by the casing, well pound, casing gas venting), manner of inhibitor application and the awareness of the personnel responsible for treating the wells. Preventative programs are valuable for wells producing Highly corrosive fluids, and test wells are important for evaluating inhibitors and their application. Such tests have been very valuable for the inhibitor manufacturer as he works with the producer in developing improved products. Keeping corrosion-control programs current is very. important. Well characteristics such as type of production, WOR, and fluid levels change, and the corrosion-control-program should change with them if pulling jobs are to be minimized, equipment replacement is to be reduced, and costs kept down. This paper discusses one such approach to optimizing corrosion inhibitor treatments.

The ability and capacity for people to communicate with one another effectively is perhaps one of the most pressing needs in today's complicated world. The written word tends to lost its meaning in a sea of gobbledygook. That in itself seriously limits people's capacity to communicate. But there are more subtle problems that affect every type of communication, including written and oral. These problems can be classified loosely under three headings: 1) jumping to conclusions; 2) closed minds; and 3) listening only to words. Everyone tends to fall victim of these shortcomings from time to time and to varying degrees in each situation. Communications suffer accordingly. It would be less than realistic to expect to correct all these problems in everyone. However, there is hope for improvement by making people more aware that these problems exist and helping them become more sensitive to them.

Stimulation techniques in horizontal wells continue to be a topic of interest and discussion. With a large variety of different stimulation practices/techniques being performed; varying from slickwater, gelled water, foam fracturing using ball activated sleeves; many people neglect the effect of fracture spacing in horizontal wells when determining the most effective methods for increasing oil/gas production.
In a review of past production wells performance with the use a of reservoir simulator; it was apparent that a large portion of the horizontal interval was not dropping in pressure and was not contributing to the well's overall production, resulting in a low EUR (estimated ultimate recovery). With the aid of a fracture simulator, reservoir simulator, logging data and local core data; a process has been developed for determining the optimal horizontal well fracture spacing. Determining the most effective fracture spacing on a horizontal interval has shown to boost production by increasing the EUR within a given drainage area.

This paper analyzes the effects on reducer torque and structural a beam mounted gas compressor on a Conventional pumping unit.

The prediction of the volumetric efficiency of the pump is one of the most important factors in the analysis of sucker rod and progressing cavity pumping systems. In most cases, the reduction of production due to gas interference in the pump exceeds by far the effect of leakage in the pump components. In this paper, the equations to determine the effect of free gas on the volumetric efficiency of a sucker rod pump and a progressing cavity pump, as a function of the downhole separation efficiency, the pump intake conditions and the fluid properties, are presented. Computer programs were written to simulate the hydrodynamic behavior of a sucker rod pump and of an idealized progressing cavity pump. The sucker rod pump was simulated for harmonic motion and for constant velocity motion. A comparison between the three cases is presented. Curves for sensitivity of the sucker rod pump volumetric efficiency to the compression ratio and clearance ratio are also presented. Finally, a much more simplified model based on constant flow rate is presented for the case of sucker rod pump. The results obtained with this model are in good agreement with those corresponding to the simulation based on harmonic motion.

Most polished rods break at the bottom of the polished rod clamp. Almost all of these breaks are fatigue failures. A study of polished rod fatigue failures entitled How to Minimize Polished Rod Breaks (Ref. 1) was presented at the 41st Annual Southwestern Petroleum Short Course in April, 1994. The study concluded that bending stresses amplified by stress concentrations from polished rod clamps are the most significant contributors to polished rod fatigue failures. The study also pointed out a noticeable absence of information on stress concentrations caused by various polished rod clamps. This paper picks up where the above study left off. Recent experimental results are reported on the effects of stress concentrations generated by polished rod clamps on the fatigue strength of polished rods. The major objective of the investigation was to determine and to compare polished rod endurance limits resulting from indention and friction style clamps. This objective was achieved by conducting fatigue tests on polished rods using both clamp designs. Test results are presented in the form of stress-cycle curves which were used to determine the endurance limits for polished rods equipped with indention and friction style clamps.

Due to the widespread manifestation of large scale miscible CO, enhanced recovery projects, particularly in West Texas and Gulf Coast regions, considerable concern has developed regarding the performance and/or durability of hydrated cement located across producing and injection intervals in CO, related wells. It is known that carbonation affects the microstructure of cement affecting both porosity and compressive strength. The CO, reactivity of a cement is characterized not only by its chemical composition, but also by the properties of the CO, medium itself, that is, partial pressure, temperature and relative humidity. However, a clear understanding of this phenomenon and its effects on portland cement is still not completely substantiated, giving rise to contradictory opinions in this particular area of research. This lead to the need and development of a laboratory program for examining the effects of supercritical CO, on preset cement, as well as the influence of carbonation on the early stages of the cement hydration process. This article presents the findings of a comprehensive study which show that after prolonged exposure to CO, under supercritical conditions, the hydration products formed in the hydration of common portland cement undergo decomposition into calcium carbonate and a siliceous residue. Cement samples exposed to the lower extremes (temperature and pressure) of a supercritical CO, environment exhibited greater reactivity under dynamic conditions as compared to static conditions, while increasing CO, pressure increased the degree of reaction regardless of the carbonation conditions employed.

Efficient Sucker Rod Beam Pumping has been a problem for years. Excessive rod and pump failures have caused lifting costs to skyrocket. This paper discusses an extensive program that was undertaken in 1978 and 1979 to maximize efficiency in the Beam Pumping System in the MCA Unit, Maljamar, New Mexico. Approximately 220 pumping wells were checked for proper design and corrections to each well were made to improve the pumping system. Each unit was checked for sucker rod design, pump design, pumping unit speed, stroke length, torque, and electrical equipment.

This discussion will be centered on the following topics: History of jet pumps as used in the Oil & Gas Industry
Problems associated with early jet pumps and surface equipment: Details of new jet pump, How the new jet pump is being configured to unload liquid loaded gas wells, New types of surface pumps for jet pump power fluid delivery to the down hole pump, Case studies where jet pumps and diaphragm surface pumps were used

This Sucker Rod Pump has a short primary plunger with a long barrel and hollow tube that slides inside a short barrel; the availability of a superior traveling valve turns the equipment into a double stage pump. A pressure compensating bushing connects the primary plunger and hollow tube. From the bushing connection to the end of the long barrel an annular space exists where the gas is compressed on the upstroke and the sand and gas is forced to move instead of settling. During the evaluation of this technology 15 equipments were installed in wells from 8-11 _API in Petroleos de Venezuela, in the Eastern Division. A considerable diminution of: GOR, interference by gas and the effect gas lock were observed. Production increase on an average of 30% per well after the installation of this type pump.

The first ever actual field tests to evaluate well bore fluid's real time impact on elastomeric compounds used for casing plunger sealing cups led to major breakthroughs in the discovery of better sealing cup compounds, previously unavailable to the industry. The drastically improved performance of carefully formulated compounds, coupled with radical innovations in over-all casing plunger design, were major factors in the development of the first truly successful casing plunger, following decades of disappointment experienced with previous casing plungers on the market. Field data, photos, and procedures will be discussed and state of the art products presented.

Three-phase, squirrel cage induction motors are used almost exclusively for oil well pumping on electrified leases. The squirrel cage motor is available with various designs, enclosures and other electrical and mechanical variations. This paper will discuss squirrel cage motors most ideally suited and generally used as a drive for individual walking beam sucker rod pumps.

This tutorial describes the components of the electric submersible progressing cavity pump system. The intended audience is familiar with electric submersible pumping systems used in petroleum production. While the electrical parts of any electric submersible system are important, this material emphasizes descriptions of the progressing cavity pump and its unique mechanical drive components.

Oil and gas producers are frequently faced with deep, low volume applications that challenge today's rod pump technology. There is a growing demand for a reliable form of artificial lift in deep, low volume, hot and aggressive applications. Operators with low volume applications that suffer from deviated well bores or applications that are just too deep and challenging to achieve long run times with a conventional rod pump can now utilize electric submersible pumps (ESPs) as an economical alternative. Historically, low volume submersible pump designs consisted of production ranges greater than 300 bpd. Those submersible pumps had narrow vane clearances, which plugged up easily, had limited gas handling capabilities, limited thrust washer areas and lower-pressure housings. This created unsafe operating conditions and limited
application ranges. New technology such as wider vane stage designs, ultra high pressure housings, higher efficiency gas separators, high temp motors and reliable down hole sensors have greatly contributed to the success of ESP's in this type of application. This paper will present technological innovations and improvements that created the opportunity to utilize ESPs in low volume, deep applications.

How lease capacitors reduce current and line losses on oil field leases is demonstrated. Information from field testing with bottom-hole heaters is presented. Use of timed restarters and heating cable on oil field leases is discussed.

An extensive electrical and mechanical testing program has been performed on beam pumping systems in six producing properties in the Permian Basin of Texas. The subject properties are waterflood or carbon dioxide (C02) flood projects which produce from the San Andres formation. The effect of motor torque mode setting and direction of rotation was studied in 30 wells. The impact on important operational indicators such as electrical lifting cost, gear box loading, and rod loading are addressed. It should be noted that much of the data used in this paper was the subject of a paper entitled "Application of Real-Time Measurement of Motor Power to Determination of Beam Pump Efficiency" which was presented at the 1994 Southwestern Petroleum Short Course. Because more data has since been obtained, the conclusions below are more statistically significant.

This paper will present and discuss the selection, design, construction, and protection of several different types of oilfield-oriented overhead electrical power distribution systems. This information will assist in choosing, installing, and/or modifying the overhead distribution system most suitable for a particular project.

This paper discusses a recently implemented electrical load shedding program at the Salt Creek Field Unit (SCFU) in Kent County, Texas. The project involves the interruption of SCFU electrical load during the wholesale utility's monthly peak load. By interrupting SCFU load during the utility's monthly peak, the SCFU electrical demand charge is reduced by $7.16 or $6.03 per interrupted kilowatt, depending on the time of year. A dual demand electrical rate schedule makes the load shedding concept possible. With this rate schedule, the demand charge is divided into two components. One demand charge is based on the highest SCFU electrical load during the billing period while the other is based on the SCFU load during the wholesale utility's monthly peak. The goal of the load shedding program is to interrupt SCFU electrical load at the time of the utility's peak load thereby reducing one component of the demand charge. A critical element to the load shedding program is the ability to predict when the wholesale utility's monthly peak load will occur. The utility's system load is highly dependent on the temperature in the utility's main load center which is located in and around Stephenville, Texas. By closely monitoring the utility's load and temperature/weather data in Stephenville, the time of the utility's peak load can be forecasted. Historical load and temperature/weather information are also utilized in peak load forecasting. Another key element is the selection of SCFU electrical load to be interrupted during the utility's monthly peak. Currently, high pressure injection pumps and artificial lift installations are interrupted for load shedding purposes. Since the interruption of artificial lift installations results in deferred production, wells must be carefully prioritized for interruption so that lost revenue is minimized. Also, limiting total interruption time and frequency during each billing period is very important in minimizing lost revenue and cycling of lift equipment. Net profit of load shedding each artificial lift installation is determined by subtracting potential lost revenue from potential electrical savings. This paper addresses the electrical rate schedule design, wholesale utility load forecasting, load shedding methodology, and results of the program to date.

The basic configuration of the Electrical Submersible Pump was conceived over fifty years ago. It was originally designed for the traditional vertical well. Development of steerable drilling tools and "measurement while drilling" techniques over the last two decades has allowed drilling wells that radically depart from tradition. To be able to derive the maximum benefit from these complex geometry wells it is necessary to understand some of the production problems and the limitations of the-Electrical Submersible Pump. The traditional well has been thought of as being straight and vertical, however the exact path of the bore hole has never been straight nor vertical for very far. Different physical properties of the rock and the angle at which the bit intersects the formation can cause the bit to skip or dig, producing an infinite variety of bore hole paths. The severity of the deviation from a straight hole is called "dogleg" and is expressed in degrees of deflection per 100 feet of measured hole (fig. 1). Modern drilling techniques allow the bore hole to be purposely deviated, or steered, in order to intersect the producing formation in particular location and manner. These complex geometry wells can be divided into two major categories, the directional wells and the horizontal wells.

The following is an update to an earlier paper compiled and presented in April 1991 at the ESP roundtable held in Houston, Texas. This paper contains referenced categories of problems that have been encountered in field operations and the solutions that have been found to the problems. The discussion for each problem/solution set is brief, but serves as an index to the particular reference, where more detail can be found. The discussion is restricted to field cases. Many excellent studies such as design techniques and recommended procedures are not covered since they are not in the context of a field study containing problems and solutions. Also, some field operational papers were not included if they presented identical information. This study was originally intended to be review of the field cases and a summary of various failures and their causes as a function of the conditions present. However, when beginning to review the papers in the literature, it became obvious that it is rare for a given paper to list detailed field conditions. In fact out of the fifty or so references examined here, only a few contained sufficient field condition data which would have allowed problems and solutions to be correlated to conditions. In addition to categorized and referenced problems and solutions, new innovations, products and operating techniques are presented.

This publication presents a non-technical discussion of the dynamic forces currently active in the petroleum industry. These forces mandate, the implementation of electronic systems to monitor, optimize and control the production of petroleum products. Once the producer comprehends these dynamic forces and their impact, the latest tools available will be discussed. The information presented will enable the reader to gain an over-view appreciation of these tools and how they will provide needed functionality for today's known challenges and tomorrow's unknown requirements.

An expository account of the elements of reservoir simulation in computers is presented for those who wish a review of or an introduction to the fundamental concept. The discussion is related to a concrete problem involving a slightly compressible fluid in a linear medium in order that the methods and results in backward and forward difference techniques can be fully displayed and compared.

In discussing contracts for purchasing or selling gas, some emphasis should be placed on the various provisions of the agreement, but more so on the type of deal that has to be made in order to purchase gas, and on the parts of the contract which have a direct economic effect on the contracting parties. This emphasis should be made when one considers what a changing, dynamic business the energy industry now is. This is brought out now to emphasize how very important the matter of gas contracting is in today's business. Certainly, with the enormous sums of money involved in the purchase and sale of gas, the significance of the legal instrument covering that transaction must be recognized. It follows that there is an added importance in the measurement and accounting for the product being sold and for the proper operations under the contract.

Empirical oil recovery forecast models were developed for waterflood infill drillings in San Andres and Clearfork carbonate reservoirs of Permian Basin. The models were developed using field waterflood databases and the geographical distributions of the ultimate recovery efficiencies. The study evaluated the incremental oil recovery by infill drilling without acceleration of expected oil recovery. Results of testing the empirical oil recovery forecast models indicated an average error of less than six per cent. The forecast models are applicable to a wide range of unit sizes. They are useful for initial evaluations of waterflood infill drilling performance and for property evaluation. The dominant factors affecting the infill drilling ultimate recovery are found to be primary ultimate recovery (geology, pay connectivity, rock properties, etc.), well spacing and development strategies. When the well spacing is to be reduced to below 20 acres, a targeted infill drilling based on reservoir geology, reservoir properties and past production performance should be contemplated instead of a blanket pattern infill drilling.

Encapsulated breakers for water-based fracturing fluids have been widely used for the past decade. These breakers provide a delayed break because the reactive chemical is separated from the fracturing fluid by a water-resistant coating. Higher breaker concentrations can be used, resulting in improved proppant pack conductivity. However, the coating is not completely impermeable. The breaker material can release through the coating under certain conditions when placed in an aqueous environment. This paper shows the breaker release rate as a function of temperature, hydrostatic pressure and aqueous fluid pH. A breaker release apparatus was developed, and tests were performed from 150_F to 225_F, 0 to 8000 psig, and fluid pH of 4, 7, and 9.5. The major findings were that the breaker release rate is a very strong hnction of pressure and temperature, but is independent of aqueous fluid pH. Fifteen percent of the encapsulated breaker is released after 6 hours at 150_F and 0 psig, whereas only 8% and 7% of the breaker is released at 2000 psig and 8000 psig, respectively. Sixty percent of the breaker is released after 1 hour at 225_F and 500 psig, while the 8000 psig breaker release is 12% after 1 hr. These findings suggest that tests evaluating the stability of fracturing fluids at low hydrostatic pressure conditions (such as using Model 35 or Model 50 rheometers) do not represent the actual breaker performance under fracturing conditions. Breaker schedules based on these low-pressure tests underuse encapsulated breakers and jeopardize the proppant pack cleanup process. Using the correlations developed in this study, it is possible to calculate the wellsite breaker schedule from lowpressure rheology tests using encapsulated breakers. Polymer-induced fracture damage will be reduced and well productivity increased.