Most exotic fluids introduced into a reservoir will cause reduction in permeability near the wellbore. Dispersed water base fluids and oil base fluids create their own unique problems, such as wettability changes, and emulsions. Prior knowledge of what drilling fluids can do to a formation will, upon completion, lead to a better diagnosis of well behavior and thus resulting in more effective clean-up and stimulation procedures. Hydrochloric acid (HCL) as a stimulation fluid has been and continues to be misused as a method to increase reservoir permeability. Incorrect application can either create a problem greater than the original and/or cause unnecessary expense to the operator. The cause of productivity impairment should first be determined before a stimulation procedure is selected. Scanning electron microscopy, X-ray diffraction, thin section petrography and core-flood analysis are effective techniques in determining the sensitivity of a reservoir to foreign fluids. Rock-to-fluid and fluid-to-fluid compatibility tests are extremely important to improve stimulation procedures and to ultimately improve production. As money for drilling and completing wells gets scarce, proper utilization of current technology can result in a higher return of investment.

Artificial Lift Systems are under constant attack from storms, load and utility grid switching and internally generated switching. The associated voltage phenomena are cumulative in nature and degrade the integrity of these electric/electrical powered systems. The cost associated with adding equipment which is designed to protect system from this type of damage is far less than the cost encountered when attempting to recover from the damaging effects.
When using Variable Frequency Drives (VFDs) in ESP and Rod Pump applications many benefits can be realized, however an increased level of awareness regarding a properly designed electrical system is needed. Input and output waveforms are distorted by the very nature of VFD technology (fixed speed AC input current / variable speed AC output current). The use of properly selected and coordinated protection, such a secondary surge suppression and chemical grounding, can effectively minimize the negative effects (increased system total cost of ownership, loss of production) of premature equipment failure due to voltage irregularities inherent to the system.

The importance of proper procedures, well data coordination, communications, subcontractors and employee training for submersible pump operations cannot be overstressed. This paper points out how some operating practices can result in unnecessary expense, and provides recommendations for helping to reduce these costly mistakes. It is felt that if these recommendations are followed, it will result in highly successful submersible operations for the user. It is recommended that the producing company evaluate the points of this paper and put into action the good working practices and training that will result in efficient operations with good economical results.

Attent ion to proven des ign parameters, such as are used to design plant process equipment, can improve the operation of petroleum production systems. A review of the development of primary extraction devices is given, along with formulae for efficiency and allowable velocities. Vane type, wire mesh and centrifugal are examined. Staggered baffles and zig-zag or wave plates are discussed. Design criteria for the application of these primary elements are compared, thus allowing the selection of the optimum type mist extractor for most desired services. The influence of liquid loading/entrainment on separator sizing is discussed. Vessel dimensions and liquid capacity are related for each type of primary element. It is shown how comparisons of advantages can help make an economic selection for any given problem.

Indiscriminate selection of production logging tools through haste or lack of knowledge has often resulted in inadequate or incomplete information on down-hole fluid movement. With the proper selection of tools through knowledge of both tools and well problems, more information can be obtained. A comparison of tools and methods is presented providing procedures which can be utilized for optimum analysis of down-hole fluid movement.

Proper cleanout of millscale and other iron oxides from new tubular goods prior to their use reduces production damage by deposition (in the producing formation) of iron solids and iron in solution. Iron removed from new tubulars by stimulation fluids has caused formation damage and reduced production for many decades. This iron is available for removal from the walls of the casing and tubing by the action of stimulation acids and erosive proppants being pumped to stimulate the well. The sources of this iron are listed below. 1. Millscale (magnetite) is a thin layer of iron oxide found on the surface of tubulars. Millscale is deposited as a result of cooling the tubular steel after heating and extruding processes are done. 2. Iron oxides have many forms, but are basically rust. Although numerous iron scales are encountered in oilfield operations, and many are contacted by stimulation fluids, they are by-products of oil and gas production. Millscale and rust arrive on location with tubing and casing, and there is little doubt that the problem exists on most locations. This paper presents a method to "pickle" tubulars to help eliminate the source of many iron deposition problems.

In the early stages of production of oil in the Pennsylvania and West Virginia fields, very little, if any, "bad oil" or emulsions were found. The small amount that was made created a very minor problem. The reason for this small amount of emulsion was due to the fact that oil produced in these fields was almost void of any foreign matter. Also, what water was produced was almost pure and very little gas was found. This kind of condition will not make an emulsion. This will be explained later.

A discussion of the properties and sensitivities of high strength tubular goods outlining selection and handling criteria which must be followed to assure satisfactory performance. High strength correspondingly reduces ductility of these steels causing them to be particularly susceptible to defects and corrosion.

During the past several years, production and service companies have been trying to solve an old problem that occurs after fracture of productive zones in the Permian Basin. Many solutions have been used with little or no success to prevent proppant flowback. The problem of proppant flowback occurs in both cased hole as well as open hole completions. New applications using old completion technology have been applied recently to improve control of proppant flowback. The technology used was developed from sand control methods dating back to the 1g70 t s. 1,2,3,4 These methods consist of slurrying the same mesh sand used during the fracturing process with a resin. This yields a complete sand resin and catalyst mixture to ensure proper setting of sand. The ability to alter the catalyst makes it an attractive alternative due to the wide range of pump times available. The original slurry was developed to place an artificial zone in a hard rock, open hole environment following a propped fracture treatment. The slurry is allowed to set up and then drilled to a size known to be smaller than the original open hole section. This will give a permeable ring of resin-set sand to prevent proppant from flowing back into the wellbore. The liquid resin squeeze technique, used in a cased hole application, was conceptually designed to utilize the in-place proppant material. This resin bonding of the proppant will create a permeable barrier preventing proppant flow into the wellbore. This paper will describe, in detail, a case study of a field in West Texas and how to prevent proppant flowback in both open and cased holes using slurried resin and sand. It will also evaluate the well's performance.

There are many types of proppants and mesh sizes to consider in the design of a fracture stimulation treatment. When considering proppants, sand (Ottawa, Texas Mining, Unisil), bauxite, intermediate strength proppants (ISP), resin-coated sand (RCS), precured resin-coated sand (PRCS) and Z-prop, the principal questions seem to be, "Which one do I select and how should I use it?" Maximizing adequate long-term productivity in low-permeability reservoirs is dependent on both fracture penetration and fracture, conductivity. How to obtain deeply penetrating fractures, contained and adjacent to the porous interval, is one of the problems that challenges the industry. The other is how to obtain sufficient fracture conductivity to effectively utilize the deep penetration. This paper discusses how to determine and obtain sufficient fracture conductivity. Fracture conductivity is a function of the proppant properties (i.e., strength, roundness, fines content, etc.), closure stress, drawdown rate, formation properties (i.e., proppant embedment conditions) and resultant propped fracture width. The engineering principles involved in the selection of the proper type and amount of proppant are supported with a case history. This is a "state-of-the-art" paper, attempting to bring the current technology on proppants together in one place.

For worthwhile oil or gas well stimulation the best proppant and fluids have to be combined with a good design plan and the right equipment. Proppant selection is one of the important areas which determines how worthwhile and how successful the stimulation treatment can be. To select the best proppant for each well a general understanding of available proppants is imperative. Also, the latest proppant properties for design are taken at downhole conditions with embedment, temperature, crushing and long term effects all being considered. After downhole permeability of a proppant is measured, it becomes a logical process to narrow the selection of the proppant to a particular class and sub-class. With information from the downhole formation or reservoir the proper mesh size can be selected to fix the specific proppant, and optimize the hydraulic or acid fracturing treatment on the well.

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. The proppant material often overflows off the sides of the conveyor when discharged from the dispensing unit. The material overflow can freeze the conveyor belt from moving.
This paper introduces a solution that solves the problem of proppant spillage from a mobile proppant conveying unit, it also reduces dust from the conveying unit, and creates a better job operation environment for the equipment operator.

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. 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.