One of the major problems in the oil field today is how to prevent unnecessary down-time due to relatively minor electrical disturbances and minimize the effect of major problems. In this paper we intend to show some of the ways in which momentary interruptions can be minimized and major faults can be cleared with a minimum of lost production.

This paper will discuss the successful installation of plunger lift systems in wells with set packers or permanent tubing. Several case histories will be presented with a discussion on the resulting production increases, cost of installation and economic information. Prior to the discussion of the case histories of the plunger lift installations with set packers, the basics of plunger lift systems will be discussed. lift, This discussion will include a description of plunger why a plunger lift might be used, the formula for determining candidates for plunger lift installations and the various types of plunger lift applications.

There are several important elements that determine the proper selection and operation of safety relief valves. This text will discuss various valve types and show how field experiences and maintenance procedures help to determine which valve is best suited for the application. This paper should be used as an outline for valve selection; Many applications are unique and the valve manufacturer should be consulted when specific information is needed.

The comprehensive Tax Reform Act of 1976 ("the Act") makes substantial changes in the taxation of oil and gas transactions. The changes most affecting oil and gas operators include "at risk" limitations on deductions for expenses, reduction in capital gains benefits allowable on certain oil and gas properties, and new minimum tax provisions. In addition, the Act's percentage-depletion provisions clarify previous laws.

Pulse Testing was developed in the early 1960's for the purpose of obtaining reservoir description between wells. Since then, several papers have been published advancing this technology to the point where it can now be considered conventional well testing. This paper reviews the advances that have been made in pulse testing technology and presents the state of the art of pulse testing as it is being used today. A method of design and analysis of pulse tests is presented along with example applications. Some of the topics considered are enhancement of pressure response by filtering, desuperposition of data, effects of well bore storage and skin, unequal rate pulses, and limitations of pulse testing.

Pulse testing is a pressure-transient method that can be used to calculate reservoir flow capacity and pore volume per unit area. This test was introduced in the late 1960"s. Several publications that describe pulse test behavior in different reservoir systems appeared in the last few years. This paper, a review paper, describes pulse testing and the information that can be learned by using it. A general overview of the relation between pulse testing and other pressure-transient tests (e.g. buildup tests) is presented. A method for pulse-test design and analysis of the data after running the test is described. The method of using pulse test data together with data from buildup and fall-off tests to select an appropriate reservoir model and obtain a reservoir model and obtain a reservoir description is presented. A field example is used to emphasize the use of the test.

The three Pump Intake Pressure (PIP) calculation methods available for sucker rod lifted wells are discussed in detail. Values of PIP obtained from Acoustic Fluid level measurements, in wells with moderate pump submergence, yield PIP estimates that agree with those from pump fluid load analysis. If PIPs determined from these methods do not agree, then the operator using the discussed techniques can make corrections to consider the unusual conditions affecting the fluid load. Field data for a significant group of wells are used to compare the PIP results of the three methods. The results show that the PIP computed using the maximum and minimum pump card loads usually calculates too low of a PIP, while the PIP computed using the valve test loads are usually too high. Data processing techniques for improving the quality of the results from dynamometer data are presented. The pros and cons of using each method are discussed.

Problem pumping often means high lifting costs. Excessive down-time because of premature subsurface pump remedial work can be reduced by proper pump specifications. The correct type of pump to be used when encountering a problem condition is half the battle toward a satisfactory solution. Proper metallurgy of the pump components is the other half.

Ever since oil well pumps were first used-in their crudest form there has been a need for controlling the pump. The controlling effort has been directed at matching the pump capacity with the well capacity. This type of control has been an objective of oil producers around the world. The value of achieving this goal has changed as the importance and value of crude oil has changed. The present conditions have placed a very high value and degree of importance on the amount of fluid produced and the lifting costs necessary to produce that fluid. Many of the pumping problems that occur in the production of oil can be traced back to the lack of proper pump control. Some of these problems include gas locks, mechanical damage to the pump, rods, gear box and excessive power consumption. With rising costs, to correct the above problems proper control of pumps has become increasingly important. There has been a decrease in the amount of manpower available to track down these pumping problems, identify and correct them. Most oil-producing fields are being operated with fewer people today than they were several years ago. During the years a number of methods have been tried in an effort to properly control pumping wells. These methods fall into two basic categories-fluid production measurement and load measurement. Various types of equipment have been developed during the last 20 years in order to properly control pumping oil wells. Some of the design and equipment met with varying degrees of success while other equipment and design met with total failure to meet the desired objective. This paper considers some of the drawbacks of previous developments; and discusses at length the development of the average motor current method of controlling oil well pumps. Following the development of this method complete field and laboratory tests were run over an extended period of time to prove the method. Conclusions reached as a result of the design and testing program are stated in the Conclusions section of this paper.

Through cooperation of Amoco E & P Sector's Hackberry Field, D-Jax Corporation, Amoco Argentina, and Amoco's Tulsa Research Center, a new type of pump-off controller for a gas engine driven pumping unit has been developed. The processes of reducing well pump off and fluid pound for a gas engine driven beam pumping unit has been to reduce shieving, engine speed, and stroke length. The problems occurring with these types of solutions are numerous. There is still the possibility of well bore pump down or a gradual increase in well bore fluid level. Both of these results are tedious and time consuming. The stroke per minute timing will have need be changed whenever the fluid level changes high or low. Or, the high fluid above pump (FAP) will begin to reduce inflow from the formation due to hydrostatic pressure buildup in the casing.

Pump-off control (POC) has been employed in significant commercial quantities for over a decade and a half. However, POC has not yet gained general acceptance. This paper considers: (1) the development of POC equipment and philosophies, (2) the current state of the art, and (3) the possible future course of POC.

The definition of flumping is when a well flows fluid to the surface up the casing annulus, plus at the same time fluids are being pumped by the sucker rod pump up the tubing to the surface. Oil wells usually flump due to high producing bottomhole pressure or due to high rates of gas flowing up the casing annulus. In a flumping wells the operator must maintain high surface tubing wellhead pressure while pumping or the gas in the tubing can unload too much liquid out of the tubing and pump action will stop. Frequently the only way to prevent flumping up the tubing is through use of a back-pressure regulating valve. The additional tubing backpressure applies more pressure on the fluid in the tubing, increasing the pump discharge pressure and stabilizing flow in the tubing. Dynamometer and fluid level data from various wells will be presented to identify and troubleshoot the many flumping symptoms.

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.