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Proppant spillage from mobile proppant conveying units used on fracture sites has been an ongoing problem industry wide. With the spillage of the proppant comes the inability to control the flow, levels in blending equipment, and the creation of dust.
Currently mobile proppant conveying units are being operated by turning the conveyor belt to its maximum speed and the material discharge slide gates are opened at various intervals to control the amount of proppant to be placed on the conveyor to be discharged by the unit.

A method is presented for predicting the transport of proppant in a fracture during a hydraulic fracturing treatment. In addition, the settling of the proppant during closure of the fracture following the treatment is considered. From the final distribution of proppant, increases in well productivity (stimulation) are calculated. The examples given illustrate that proppant settling during fracture closure can determine the success or failure of a hydraulic fracturing treatment.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.