Training techniques used in Continental Oil Company's Well Pumping Short Courses will be discussed. The API recommended practice (RP 11L) for calculating well loads, peak torque, polished rod horsepower, etc., will be presented in "building block" form. An understanding of instantaneous net torque calculations using torque factors will be secured. Typical rod pumping problem areas and possible solutions by utilizing standing valve and traveling valve tests vs. pre-calculated loads, shapes of dynamometer cards, orders of dynamometer cards and over-travel and under-travel dynamometer cards will also be presented.

In this paper we will explain why high gas/oil ratio wells are difficult to pump and we will discuss and explain past methods and lifting practices. Reasons why past methods were not entirely satisfactory, and types of equipment used in conjunction with those methods, are mentioned. Improved equipment and the results of its application, compared to former practices, will be discussed.

The ever-increasing demand for additional energy sources and hydrocarbon products has pushed the search for new petroleum reserves to ever greater depths. As depths increased and well loads became successively heavier, the need also arose for higher capacity and more effective artificial lift systems. In the past, the simplicity, efficiency, and reliability of the beam pumping unit have made it a favorite with many operators, when pumping loads were light to medium. But when large volumes were to be lifted from deep wells, or massive volumes from shallow to medium depths, this historic system was often incapable of producing the required fluid, and other artificial lift methods had to be employed. Challenged by these limitations, designers of the various components of the beam pumping system redoubled their efforts to increase beam pumping capacity by upgrading and improving: (1) bottomhole pumps, (2) pumping units, (3) prime movers, and especially (4) sucker rods. One beam pumping innovation, which has now been in service for some years, is the so-called Mark II unit (Fig. 1) made up of the traditional components of walking beam, post, cranks, horsehead, pitman, etc., but rearranged to form a reversed-type geometry, with certain unique functional and kinematic properties.

During the past 10 years operators in southwestern Kansas and the Oklahoma and Texas Panhandles have been confronted with the ever increasing problem of removing salt water from gas wells. The majority of these wells are low pressure, shallow gas wells and are located principally in the Hugoton and Greenwood gas fields. The salt water problem in gas wells first became apparent during the early 1950's when the edge wells in the Hugoton Field were being drilled and completed. In order to keep the wells from "logging off" and curtailing gas production, small diameter tubing strings from 1 to 1-1"2 in. were installed inside the production casing. The gas was produced through the casing and the salt water was removed through the tubing intermittently either by manual blowing or by a time-cycle intermitter. When it was found that this method was not very efficient due to large volumes of gas being vented to the atmosphere to raise small amounts of salt water, gas lift valves were installed in the tubing strings. This system proved to be satisfactory and many operators began equipping their water problem wells with gas lift valves in 1954. Many wells are still utilizing this system today.

The use of Macaroni tuning is not new; for many years oil producers have been successfully pumping fluids through and around this tubing. However, these applications have generally been limited to wells above 3,000 feet. This limitation, imposed because of the failure of the mechanical joint in reciprocating service, can be materially altered or entirely eliminated if we understand the problems and design accordingly. To do this, we must first determine the forces which are present in pumping with Macaroni sucker rods and evaluate their magnitude. Some of the forces present are: dead weight of rods, dead weight of fluid, acceleration and deceleration, fluid friction and mechanical friction. All of these forces are present to some degree in a reciprocating rod string, and the sum of these forces constitutes the polish rod load.

Electric motors are operated with cyclical loading on beam pumping units. However, motors are rated for steady loads. The performance of the motor changes when applied to a varying torque load, The motor efficiency, energy consumption and available torque are reduced, A method of calculating the effective ratings is presented. A comparison of operations on both conventional and unconventional pumping units is outlined, Economics of optimum motor sizing are discussed.

A step by step presentation of torque factor calculations, with illustrations, demonstrates the simplicity of their use in everyday pumping problems and equipment selection. Paper considers the derivation and use of permissible load diagram, and touches on internal unit stresses and how they affect unit construction and application.

Lubrication is one of the most important influences on the life of a pumping unit. However, successful operation requires a well balanced program beginning with the careful selection of equipment and lubricants and carried out with a well planned maintenance program. This paper analyzes the lubricant characteristics required for pumping unit bearings, gear units, electric motor drives, pumping engines, and hydraulic unit fluid. General recommendations are discussed for the maintenance of the lubrication systems of this equipment. General principles of the lubrication of the equipment are discussed; however, it is beyond the scope of this paper to cover detailed recommendations for the different models of these units.

In order to produce available fluids, pump jacks used at surface have been engineered to stroke as slow as 6 (six) strokes per minute (SPM) and as fast as 14 (fourteen) SPM. Depending on available production, pump length (.stroke) and pump size were the only two other variables taken into consideration. This approach works well until a time is reached when production has declined to a point where production inflow no longer matches pump capacity. As production declined, the typical method of compensation was to shorten the stroke, downsize the pump and remain at a constant SPM somewhere around 10 (ten) SPM. As production declines this approach eventually results in partial pump fill even with small bore pumps, short stoke and slowing the unit as much as possible with current sheave limitation. At this point it is physically impossible to fit a large enough sheave on the gear box or small enough sheave on the electric motor to reduce the speed below approximately 6 (six) SPM.

We will show, by example, cases where repair costs and downtime could have been greatly reduced simply by paying more attention to the pumping unit or by working together to get potential problems taken care of before catastrophic failure occurred. But, who in your organization can best detect these potential problems, and what are the tell tell signs. The purpose of this paper is to help you realize the possible cost savings of a preventive maintenance program, establish who can best prevent failures, and what they need to look for.

Pumping units, with their tremendous power, inertia, heavy moving components, and height have come under the scrutiny of safety departments for service companies and operators alike. Safe operation of this equipment is a matter of developing sound, strictly enforced, operational procedures and pumping unit design. This paper will examine several approaches by various manufacturers and after market companies to enhance the safe installation, maintenance, and operation of the pumping unit.

A 1985 survey of 123 oil operators across the United States by an independent market research company estimated that 8% of all sucker-rod purchases were fiberglass. That same poll estimated purchases in the West Texas and Eastern New Mexico region to be 18% of the share of all sucker-rod purchases for that area. Only 8% indicated they would never consider using fiberglass sucker-rod. The increased presence of this innovative product represents a significant change in an old system. The need to eliminate corrosion, increase production, and reduce kilowatt consumption has always been a problem in our industry. The urgency of this problem received considerable attention after the Arab oil embargo of the early 1970"s. The introduction of the fiberglass sucker-rod coincided with the times. The resistance to corrosion was perhaps the primary purpose for many evaluations of fiberglass sucker-rod. Other initial tests were begun because of the need for well-load reductions that would result in lower gear-reducer torques, less structure requirements, and reduced kilowatt consumption. Lighter loads also allowed for longer surface strokes and consequently, more fluid. The advantages of fiberglass sucker-rod were recognized and documented to be a valuable addition to the artificial beam-lift. in our industry. Today, this sucker-rod undoubtedly is a mainstay The widespread use and acceptance of fiberglass sucker-rod throughout the United States and particularly in West Texas is notable. The use, however, has been most often as a substitute for steel sucker-rod with few other changes in the rod pumping system. The advantages realized by injecting this new suckerrod into the conventional pumping system can be increased even further by changing the conventional pumping unit into a more compatible machine. The scope of this paper is to review those changes that will enhance the use of fiberglass sucker-rod. The proven advantages already noted can be extended over and beyond with the careful selection of the pumping unit.

When a load is applied to the well end of a pumping unit it results in a torque around the speed reducer crankshaft. This resultant torque is a function of the geometrical design of the unit and the crank angle. Under constant load conditions the torque is constantly changing since it varies with the crank angle. Under static conditions and when considering only the applied load and the unit geometry (not considering the weight of each component part of the unit, the counterbalance being used, or the inertia effects) the torque around the crankshaft is the result of the applied load times a built-in multiplication factor. This multiplication factor is commonly known as the torque factor. Since the torque factors vary with the crank angle there is an infinite number of them. To simplify their use the American Petroleum Institute has devised a form for recording the torque factors at only every 15 degrees.

Operating costs are but a fraction of the price per barrel of oil or cubic feet of gas we sell. In sucker rod pumping, this fraction is extremely critical and can quickly mean the difference between gain or loss to your company or yourself. Your wage or profit is derived from operating expense and gross income; therefore, it behooves each of us to properly manage operating costs so that the returns will not only come to our company but also to ourselves. A constant program of well analysis employing understanding, prudent practices and applied techniques is necessary. Presented herein is a program of managing pumping wells with case history results. Even though, a specific program is discussed, it will apply with certain modifications to any company.

The control of pumping well failures at an optimum level requires access to equipment failure and maintenance records which adequately describe performance. It is necessary to know where failures and maintenance are occurring, what equipment is involved, the location and cause of failure, the nature of maintenance and costs. Problem wells can thus be isolated and corrective measures initiated. Further, it is possible to evaluate new materials, producing practices and inhibition methods to generally improve the performance of downhole equipment in all wells. Electronic data processing is a means of providing operating personnel with a complete failure and maintenance record in a form which permits accurate, continuous analysis of equipment performance.

This paper contains a brief description of the component parts of submergible pump to wells of various conditions is discussed. Operation results are reported for both oil wells and water supply wells.

In these days of budget constraints due to unstable oil and gas prices, many companies have begun purchasing more and more used production equipment, including pumping units. In some cases they have been able to reduce "up-front" capital expenditures only to later find that there can be significant costs in repairs to this same equipment. This paper will examine the precautions and considerations that should be made before the purchases are finalized. We will review what we consider the six (6) major areas of concern: 1) the age and history of the pumping unit, 2) the gear reducer, 3) the unit's structural integrity, 4) the structural bearing assemblies, 5) additional equipment included in the purchase and, 6) the reputation of the used equipment supplier. While we recognize that there are many used equipment dealers supplying quality reconditioned equipment, the purpose of this paper is to educate the buyer about what to look for when preparing to make this capital expenditure.

In order to get the maximum benefit from dynamometer well studies, it is essential that all of the factors involved in the pumping problems on each individual well be viewed as a complete picture. Each factor involved should be brought into focus and fitted into the picture as a whole. Fig. 1 illustrates a mechanical polished rod dynamometer.

A successful approach to oil and gas reservoir development requires knowledge of reservoir fluid
properties. It is therefore essential to determine the fluid's Pressure-Volume-Temperature (PVT)
behavior in order to obtain the necessary parameters for proper reservoir management as well as satisfy
regulatory classification requirements. Experience has demonstrated that PVT data obtained in a
laboratory is the preferred approach to fluid property description. When laboratory data are not available, correlations or equation of state computations are often used to estimate reservoir fluid behavior. Correlations are approximations to specific regional properties, and untuned equation of state calculations can produce erroneous results. Using case histories, we compare the inherent limitations in the calculated approach to PVT data derived from laboratory studies, and re-acquaint reservoir engineers with field sampling procedures, laboratory testing, and data analyses.

This paper presents a computer based tool for those wanting to use the wave equation in their beam pumping design activities, but do not require the needs of a more sophisticated, full featured program. This program properly handles the problems faced by a person responsible for designing what could be termed normal rod pumped installations. The output of the program includes pump size, rod string, surface unit size, and motor size for an input depth and production rate. The author has found that accepted design practices are not used much of the time. Whether it is because they are too cumbersome and time consuming or that acceptable knowledge about proper design procedures are not widely understood, I do not know. The objective of this software is to help the designer implement state of the art beam pumping design technology without getting buried with details. The program is a WindowsTM program requiring Windows 3.x and a 386 class computer or better. All important input and output information is available on a single window displayed for the user. More detailed information including graphs may be optionally displayed. It uses a rapid solution method to the damped wave equation allowing the user to see immediately the effect of changing a parameter such as tubing anchor, stroke length, stroke rate, and pump diameter. Correlations are used for the motion of conventional, Mark llTM and air balanced units. allowing the program to determine the size of the pumping unit required. Tapered rod strings (API taper) and Fiber Glass Steel combination strings are allowed. A full featured context sensitive help file is available to the user. This means that whenever the main screen is active you can get help by simply pressing it. The program is suitable for use on a desktop or laptop computer with or without an attached printer. Provisions are made for results to be saved to files for later examination.

The major portion of domestic oil is produced by rod pumping systems. Of the total 527,000 domestic oil wells 403,000 are rod pumped. In 1971, $157.5 million was spent for labor and material for downhole repair of these wells. This amount does not include production losses while the wells were being serviced. In that the average pulling job cost was $418.63l it is possible that the production losses exceeded this direct maintenance cost. When the total cost for maintenance and the volume of oil produced are considered, it is evident that even a small decrease in maintenance or a small increase in producing efficiency can have a significant economic impact. This paper considers the development of a new concept for controlling and monitoring rod-pumped oil wells. The development of the hardware and the techniques for implementing the concept are an integral portion of the consideration.

Field performance of plastic coated tubular goods is directly related to the following critical factors: 1- Metal cleaning and surface preparation 2- Adhesion between coating film and metal substrate. 3- Proper curing of the coating film. 4- Continuity and uniformity of the coating film. This paper deals with the various quality control techniques that are used to assure that these critical factors are controlled within specified parameters.

The determination of the correlation between petrophysical data, and core data is essential in the determination of reservoir rock properties. The goal of this study was to design a computer algorithm, which will use the geophysical inverse theory to deduce different reservoir facies, from well log responses, by utilizing statistical relationships between the well logs and core derived lithofacies information. In most oil and gas fields only a minority of the wells are cored. As a result, determination of reservoir rock properties is mainly dependent on the interpretation of geophysical log data. An objective approach to analyze well log data to determine the reservoir rock properties, would speed up the interpretive process and would also enable the researcher to correlate information between wells and incorporate a-prior knowledge into their interpretation. Detailed core and petrographical analysis was conducted as the first step in establishing statistical relationships of lithological data from four cored wells. Petrographically sixteen major rock types (lithofacies) were identified. Secondly, a valid forward model, which is a requirement in any successful inversion process, was constructed by the usage of mathematical formulation of well logs, and the petrographical data obtained from cores. Well logs used for this study include Neutron, Spectral Density including Bulk Density and Photoelectric Absorption Index (Pe), and Borehole Compensated Sonic (Interval Transit Time) logs. A unity constraint was also used as a supplementary log data. Thirdly, an inversion method, which can incorporate the results of core analysis and petrographical information as apriori geologic information, as potential constrains in the inversion itself was determined. The facies observed between wells in a given oil and gas field are related to each another. Therefore, using the a-priori information from the cored wells, with reservoir facies control, to determine if results from selected well(s) can provide lithofacies information in the remaining wells would improve the reservoir management efforts. An inversion algorithm, using a-priori geologic information was tested on four cored wells. Inversion method was tested for different a-priori geologic information cases where the examined facies were grouped in sixteen, fourteen, eleven, and five lithofacies classes. The robustness of the inversion results was found to depend on the a-priori information provided. Lithofacies inversion, using five lithofacies classes, showed reliable estimations for the purpose of depicting possible reservoir versus non-reservoir zones. The method used was also able to reliable identify most of the eleven facies classes. Inversion, using sixteen and fourteen different facies, showed to be a valuable tool in determining the gross lithology.

New methods for quantifying pump leakage are described. These methods extend the effectiveness of dynamometer analysis and can lessen the dependence on well tests in determining the degree of pump leakage. Actual examples are included to illustrate the techniques. A detailed description of traveling and standing valve leakage checks is also included.

Environmental stewardship has been and continues to be a critical component of the oil and gas industry, as exploitation of shale and other unconventional gas reservoirs requires large volumes of water for economic and efficient production. Evaluating and communicating the hazards of chemicals is done in a highly variable manner across the world. However the recent adoption of the Globally Harmonized System of Classification and Labeling of Chemicals (GHS) by multiple Global regulatory bodies has brought international consensus to hazard criteria and definitions. This system is being implemented with REACH in the EU. In the US OSHA has just proposed the GHS criteria as the basis for modifying their hazard communication regulations. This standardization ensures information about hazards and toxicity of chemicals is more universally available, to enhance protection of human health and the environment during handling, transportation and use. It is this scheme that we are beginning to utilize as the basis for the ranking of products and systems. This paper will describe the evaluation and implementation of a practical and quantitative process of ranking well servicing products based on their safety, health and environmental impacts. The ranking allows operators to select and use products that best fit their environmental stewardship goals, and provides scientifically sound tools for better research and development, and educational efforts.