A greater number of deviated wells are being drilled to increase production and prolong the life of a well. Many times the build rates are very high and result in a well that is very difficult to artificially produce. Designing a pumping system that will give extended run times is an important part of maximizing profits. Working with Crimson Resources in the Bakersfield, CA area and ChevronTexaco in the Eunice, NM area, R&M Energy Systems has completed several case studies. We will examine these studies, showing best practice and cost saving.

In 2006, 18 subject wells were selected to increase the Mean Time between Tubing Leaks by strategically installing EndurAlloy Tubing. From August 4, 2006 through August 31, 2008, failure performance was monitored for these 18 wells. All 18 wells were initially installed with bare 2-3/8" tubing and 6 joints of 2-3/8" EndurAlloy on the bottom. As a result of 19 well service events (17 failures and 2 non-failures) in 10 wells, initial tubing designs were modified from the original design.

Recent developments of casing plunger technology have provided reliable tools that successfully remove well-bore fluids and reduce liquid loading in marginal or stripper gas wells producing in 4 _ inch casing strings of nonuniform casing weight. These advances are the result of better selections of elastomeric compounds suitable for variations in the casing inside diameter that occur with non-uniform casing weight strings in deeper wells. Significant advances in the mechanical design permit more efficient sealing of the elastomeric sealing cups with the
casing inside diameter variations encountered in non-uniform strings. The specific difficulty presented by 5 _ inch casing is the much larger variations in casing inside diameter that exist in common casing weights used in deeper wells. The status of field tests and current results will be presented as part of the ongoing development of casing plungers in broader applications

The purpose of this paper is to provide a concentrated review of significant water characteristics and treating methods as related to steam flood boiler operation. In recent years, considerable interest has developed in the direct application of high pressure steam for the purpose of recovering crude oil not obtainable otherwise. With the increasing size and number of steam flood operations; there has been a turn toward higher capacity generators and higher operating pressures. As these pressures increase, water supply characteristics and water treatment methods have increased in importance.

Fluid pound is thought to be a result of the pump hitting the fluid level when the pump is partially full of gas. However gas always is compressed to a value of pressure sufficient to open the traveling valve before the pump hits the fluid. The load on the pump is released very quickly and the pump is traveling faster when fluid pound occurs than at the beginning of the stroke. However, most down hole dynamometer cards do not show compression when fluid pound occurs. Also, the concept that there is fluid pound with gas in the pump at low pressures and gas interference when the pressure seems to be accepted. A model and all formulas for fluid pound and gas interference is presented and programmed into a short wave equation program. All code and formulas are shown. Results of high and low intake pressures on pumping with incomplete fillage are shown on the bottomhole dynamometer card and on the rod string loading. Also, effects of pumping speed and degree of pump fillage are shown on the dynamometer cards and the rod string loading. Conclusions on what effects fluid pound has on the pump system are presented, some of which conflict to some degree with traditional concepts.

There have been many papers, both technical and non-technical, written on this broad subject. This paper will be directed to those in attendance who are primarily responsible for the amount of crude oil that can be accumulated in the stock tanks. Improper operation of the surface pump is the major cause of failure in this assignment.

Foamed fluids have indeed become recognized as effective fluids for stimulation treatments. The unique properties of foam make it particularly suited for stimulation. The low fluid loss, low liquid content and high proppant-carrying capability of foams are among the many advantages. In addition, the lightened fluid column provides a built-in gas assist in returning the treatment fluid. Foam stimulation, however, often presents abstruse problems in fluid design and application. Successful foam stimulation treatments require careful design of foam quality, bubble texture and half-life. These design features are influenced not only by fluid volume and gas control, but also by surfactant and stabilizer selection. A variety of liquids can be foamed, such as fresh water, brines, acid, alcohol, hydrocarbons and combinations thereof. Thus, there is growing need to understand the chemical phenomena involved in producing high quality, stable foams in all these systems. This paper presents a review of the surfactant types commonly used as foaming agents. These surfactants may be classified by their ionic nature, which often influences performance. Anionics (soaps), non-ionics (alkyl polyoxyethylene), amphoterics and cationics (amine derivatives) are available for use as foaming agents. The performance of such additives in water, acid, alcohol, and hydrocarbon systems is compared. In addition, the chemical stress factors which must be considered when selecting surfactants for a foam treatment are outlined. These include formation character, interaction with other fluid additives, and surfactant wetting properties. Techniques for stability enhancement are discussed.

There are several factors which differentiate the operating methods of the independent operator from those of the major company. Some of these differences have a rational basis; some of them are debatable, while others may prove costly to the independent in the long run. As a starting point for this paper on the methods of independent operators, a definition of the independent operator, as used in this paper, should be given. This paper is concerned with the independent operator who is either a small individual operator beginning operations with limited cash, or who is that same operator after he has established production and whose main task is to increase his reserves through the investment of his existing oil income. The large integrated independent operation does not fall within the scope of this paper.

Failures in the sucker rod industry can be costly and time consuming. As an end user in this industry, it is very critical to understand the mechanics behind couplings. This paper addresses some of the important aspects of couplings which play an important role in the overall reliability of the rod string. The topics addressed in this presentation are as follows: 1. Strength of material analysis of coupling and sucker rods, 2. What happens to a sucker rod coupling joint during an improper makeup process, 3. Types of manufacturing processes for couplings, 4. Recommended field practices.

The Office of Pipeline Safety (OPS) is assigned the responsibility for the Federal gas pipeline safety programs. These responsibilities involve a network of more than a million miles of gas transmission pipelines, distribution systems, and non-rural area gathering lines. Those systems under OPS jurisdiction are constructed, operated and maintained by more than 2990 separate operators who supply 40 percent of the nation's energy needs while serving 41 million customers. Age of the systems range from "brand new" to those which have been in the ground for over 150 years, so the duties of the OPS involve a variety of engineering and operating challenges. In addition to the gas pipeline safety programs of the OPS, the office also handles the technical details of liquid pipeline safety, the responsibility for which is assigned to the Federal Railroad Administrator. Provisions of those liquid pipeline safety programs affect some 130 interstate oil and products pipelines having 230,000 miles of system

This paper will highlight the overall effectiveness of fiberglass rods used in a portion of the Eagle Ford oil shale play. Data captured form real time SCADA software as well as from the POC, will be utilized to construct a clear picture of how fiberglass rods perform. The benchmarks used to determine the efficiency of fiberglass rods will be capital cost and LOE, power usage and fluid production.

Fiberglass sucker rods (FSRS) were developed in the early 1970s as an alternative material to help combat problems caused by corrosion. As with most new products introduced to the oil production industry, there were numerous problems to overcome before the product was accepted as a viable tool by oil producers. Over the Past ten Years many situations have arisen that have caused aggravating problems to users of FSRs. Many of these situations were caused by improper use of the rods, but some of the problems resulted from poor manufacturing processes. This paper identifies many of the problems associated with using FSRs and discusses what has been done to overcome these problems. The author details the evolution of the FSR and documents many of the benefits, including increased production, lower lifting costs, gear box torque reduction, and energy savings. The purpose of this paper is to answer often asked questions about string design, installations, hot oiling, fishing, etc. These answers will provide additional information to users of FSRs, former users wh have elected to quit using the rods, and non-users who are reluctant to use fiberglass rods due to reported difficulties

In many cases fast identification of the type of problem occurring in a oil, gas, injection or gas storage well is needed before remediation of the problem can start. The longer it takes to identify the problem the more expensive the problem becomes in lost production. Misidentification of the problem can lead to mistreatment which at best does nothing to help the well and could cause additional damage further complicating the well problems. What is needed is a set of simple tests that can be done in the field to tell the difference between organic and inorganic type problems. Is it a paraffin, asphaltene, emulsion, reverse emulsion, bacterial slime, scale, or solids problem? What type of treatment is needed? A set of simple tests will be presented that can determine the type of problem being experienced and what type treatment is needed. Case histories will be presented.

In order to select the appropriate inhibitor for a given application, two outstanding pieces of information need to be known. They are: "How much corrosion will occur in a given length of time under the specified conditions?" and "How much corrosion can be accepted?" The amount of corrosion that will occur in a given length of time can be determined by running a test which will duplicate the desired conditions; but, the amount of corrosion that is acceptable is somewhat arbitrary. In this paper, an attempt will be made to give the reader an understanding of how tests are run to determine the amount of corrosion that will occur and to help develop a feel for the amount of corrosion that can be accepted. However, before going further, we should review the fundamental definitions of "corrosion" and "inhibition".

This paper briefly summarizes the laboratory studies that have led to the development of the new, high-strength bauxite proppant, describes field applications of the proppant, and discusses the results of a detailed economic analysis for a particular field. We expect that wide-spread use of the new proppant will be economically justified in the future.

There are, at present time, eight sucker rod manufacturers in the United States. They all manufacture sucker rods and coupling according to the specifications set forth by the American Petroleum Institute. In view of this, any discussion of the care and handling for sucker rods and couplings would quite naturally apply to any and all makes of sucker rods and couplings, regardless of the manufacture.

The purpose of this discussion is to present some of the factors involved in the design, operation and maintenance of field compressor installations and to point out some of the advantages of using the packaged compressor units for this service.

This paper will examine the design, economic factors, field installation, performance, and field testing of regenerators(exhaust heat recovery systems) installed on existing industrial gas turbines. The information contained in this paper was primarily derived from the conversion in the field of four industrial gas turbines of the 10,750 brake horsepower (ISO) range from simple cycle to regenerative cycle operation.

It is important that all electrical contractors on location perform quality work. The end product of their work must meet OSHA regulations, NEC and API code standards. OSHA regulations are enforced by the federal government, whereas, industrial codes do not generally have the force of regulations. Reduction of field operating expenses will be achieved by upgrading the electrical systems. Better electrical systems will reduce field downtime and this will generate more production. During the electrical upgrades, all deenergized powerlines must have a phase-phase fault and a phase-ground fault established. These faults change the characteristics of the powerline, which is an OSHA regulation. The major cause of damage to electrical equipment is incorrect fuse sizing and improperly wired control panels. An alternative to relocating powerlines is to place fused cutouts with attached lightning arrestors on the conductors. This will allow the powerline to be deenergized during well workovers. Upgrading the electrical systems will improve workplace safety for the employees.

The advantages and techniques of extended period batch treating as compared to conventional treatment are presented. Results of field tests in central Kansas are reported.

A new gelled acid was evaluated in the West Texas, Southeast New Mexico and Oklahoma areas. The purpose of this evaluation was to determine how successful a gelled acid, prepared from xanthan polymer, would be in the following formations: Ellenburger, Blinebry, San Andres, Clearfork, Canyon Lime, Strawn Lime, Grayburg, Devonian, Drinkard Dolomite, Viola and Chester. Treatment depths vary from 4,000 to 22,000 ft. Treatment temperatures vary from 70_ to 310_F. Treatments were performed on both oil and gas wells. The age of the wells stimulated varies from new to 30 yr old. The concentration of gelled acid remained constant at 15% HCl. The concentration of gelling agent remained constant at 60 lb/1000 gal. The size of the treatments varied from 5,000 to 80,000 gal of gelled acid. More than 20 treatments are summarized. Several types of acidizing techniques were employed using gelled acid. These treatments vary from one to nine stages with and without diverting agents and with and without leakoff control additives. These treatments vary from 2 to 15 BPM. Some of these treatments contained 20/40 Sand, N2 and/or radioactive tracers. Production figures for the wells treated are discussed, as well as pertinent related information.

Initially, the waterflood operator must establish that he has a biological problem. This evaluation is best accomplished by a complete microbiological examination, made in the field, or of the waterflood system. If such a problem is found to exist, then the choice of a chemical as an effective bactericide depends upon economics, compatibility with water, plugging tendency, and toxicity.

An acidizing technique has been developed for treating carbonate reservoirs that will give deep penetrating fractures with high flow capacity. Production results from these treatments have been excellent. The technique uses the principle of hydraulic fracturing with a thickened fluid. Instead of using a proppant in the fluid, acid is used to produce flow capacity by controlled etching of the fracture system. Overall treatment success has been good. New and old producers with varying productive capacity have been treated. New wells have performed at least equal to and in most cases better than conventionally treated offset wells. Some old wells have performed exceptionally well; others indicated no favorable increase in production. The advent of complex fracturing fluids led to the idea of using a viscous pad to control leak-off of acid for more fracture height and width. These factors, it was theorized, would give greater acid penetration. The method was first tried in a well where conventional treatments had been unsuccessful. Results, which were good, led to laboratory work to determine possible reasons of success. This work indicated that the fingering of thin acid through a viscous fluid was the key to the treatment. Figures 1, 2 and 3 show laboratory models illustrating what occurs in this treatment. An analytical procedure for treatment design followed this investigation. Figure 4 is a typical computer-designed treatment.

Previous methods to detect and locate fluid flow behind well casings such as temperature, radioactive tracer, or acoustic noise have been successful but often difficult to interpret. An alternative method which is specific for detecting water flow (or CO2 flow) is the oxygen activation log. This paper presents field examples from West Texas of the Water Flow Log which is based on a new approach to oxygen activation logging. Each example demonstrates the importance of this measurement in obtaining a conclusive interpretation to difficult production problems caused from channeling fluids behind pipe.

Previous methods to detect and locate fluid flow behind well casings such as temperature, radioactive tracer, or acoustic noise have been successful but often difficult to interpret. An alternative method which is specific for detecting water flow (or CO2 flow) is the oxygen activation log. This paper presents field examples from West Texas of the Water Flow Log which is based on a new approach to oxygen activation logging. Each example demonstrates the importance of this measurement in obtaining a conclusive interpretation to difficult production problems caused from channeling fluids behind pipe.