Gas migration or "gas cut cement 'I has been an industry problem for many years. This paper discusses the testing of six different cement slurry additives and a saturated saltwater slurry, all designed to prevent gas migration. The slurries were tested for their effectiveness at preventing gas migration at low pressures, such as is experienced offshore in shallow gas sands. Test equipment of a new design was fabricated. The slurries were exposed to gas pressure at the bottom of a 17 foot cement column in 1-1/2" pipe and the volume of invading gas measured. The hardened columns were then cut into sections to observe the channels created by the gas. The study showed that none of the products were able to completely stop the gas migration. Some products did appear to perform better than others but none were completely effective. The testing showed several of the slurry's properties to be associated with the formation of gas channels. In many of the tests, unexpected and as of yet unexplained gaps enveloped in the cement columns as the cement hardened. Based on these results, additional testing is being conducted.

A discussion of the selection of gas regulators and controls with special emphasis on design, material of construction, and sizing. Sizing equations, with example problems are presented. A glossary of control industry terminology is included.

Natural gas presently supplies approximately one-third of the energy used in the United States. The current critical shortage of natural gas presents a challenging problem to the pipeline industry, the consumer and the producer. Only through cooperation by all three parties and the Federal Government will it be possible to continue to supply even the current percentage of the energy used in the United States through natural gas.

Gas turbines are being utilized as the prime movers for Gulf's Goldsmith (5600-ft.) Field Water Injection Station. The Goldsmith (5600-ft.) Field is located in Ector County, Texas. This paper will endeavor to describe the installation, operation, and economics of using gas turbines as prime movers. This paper will cover a period of almost 5 years, from initial installation in April 1961 to January 1966.

Higher gas prices have presented new opportunities in gas fields. An imperative issue throughout these fields is liquid loading. This paper discusses and presents results from a low rate, low cost deliquification project. Inexpensive pumping units with a small motor and pump are installed to keep water off the formation, enabling the production of gas. This is a long term solution allowing the well to produce to its economic limit in an efficient, low maintenance system.

There are several concepts now available in the industry to pump water downward below a packer in a gas well and allow the gas to flow freely up the casing of a gas well. This reduces the flowing gradient and allows gas flow to occur at a lower flowing bottom hole pressure. Also it eliminates any water disposal problems. This can now be done with ESP systems, PCP systems and also beam lift systems. In order for these systems to perform, a zone below the gas producing zone must be available where the water can be injected below a packer. According to Enviro-Tech Tools, State Regulatory Commissions are classifying this method as a Class II injection well, and as such they require underground injection control permits. This paper centers on discussion of some systems using modified beam lift systems to inject water in a gas well to enhance gas production. Systems are reviewed and some field experience is discussed.

Various treatment fluids and techniques have been used in attempts to stimulate gas production from the Morrow Sandstone formation in S.E. New Mexico. None of the treating fluids or techniques use in the past have given consistently successful results. Recent developments in stimulation fluid surfactants and refined treatment techniques have improved the operator's chances for successfully stimulating the Morrow. This paper reviews the problems associated with the Morrow and outlines treatment procedures and materials to use in stimulating Morrow gas wells.

A major objective of open-hole log analysis is the determination of the fluid content of the porous formations surrounding the wellbore. However, engineers frequently encounter severe difficulty when attempting this determination in low porosity pay zones because of deep, thorough flushing of the near wellbore formation by drilling mud filtrate. This problem is compounded flow pressure gas overlies oil or water, especially when resistivity logs are not available. This difficult arises because virtually total replacement of the gas by mud filtrate will suppress the gas effect which porosity logs experience in gas-saturated zones. The technique described in this paper will help to identify gas accumulations and gas-liquid contacts in the reservoir in situations in which mud filtrate flushing has hindered such identification. Using only the dual porosity log, the compensated neutron-density log, and the definition of density-derived porosity, the log analyst can easily and accurately locate gas zones and gas-liquid contacts, thus saving the costs of additional well logging, formation testing, and/or coring.

The paper presents the results of a study of dynamometer cards and pumping units of different dimensions. The purpose of the study was to determine methods of reducing gear box torque. Generally, this torque is the most expensive item in a sucker rod pumping unit installation and the use of a smaller sized gear box is almost always economically justified. The study that is reported in this paper is aimed at methods of selecting pumping unit dimensions and counterweights so that the smallest possible gear box torque is developed. The study has been made using typical dynamometer cards to reflect typical rod loadings. A mechanical device was used to digitize the dynamometer cards: then a computer program was used to calculate gear box torque for different kinds of pumping units.

The success of fracture-acidizing treatments in carbonate formations at high temperatures of 250- 400_F depends upon the in-depth penetration of live acid to produce effective etching of the fracture faces. In the fracture-acidizing treatments, viscous solutions called pads are injected ahead of the acid to improve acid penetration. Fracturing fluids which remain highly viscous at elevated temperatures create fractures with high fluid conductivity in both sandstone and carbonate reservoirs. With the greater flow capacity through the fracture, the depth of fracture penetration can be extended with larger volume treatments to increase productivity of the treated well. This paper describes the development, important characteristics, and a field test of a new high-temperature fracturing fluid called gelled PROD fluid. The viscous fluid was developed and tested in the laboratory in a cooperative project with personnel of Drilling Specialties Company, a Phillips" subsidiary.

This paper deals with the practical aspects of safety when drilling wells that encounter hydrogen sulfide gas, the type and amount of equipment needed, the grade of air used, the use of air compressors, and the characteristics to look for when renting or buying safety breathing equipment. The paper explains the how and why of the physiological effects and after-effects of H2S. The author feels an important part of the training for an H2S environment is the knowledge of what happens when H2S is taken into the lungs, the steps that must be taken to remove it, and how to prepare workers for an H2S environment. The paper attempts to dispel many of the myths and old wives" tales heard concerning H2S around the oilfield today.

The Petroleum Industry, as in many industries, always has had its safety problems, but down through the years continuous effort has served to make it one of the safest occupations in American industry.

The Permian Basin is one of the major hydrocarbon producing provinces in the United States. It produces approximately 22% of the nation's oil and substantial amounts of gas. Geographically, it covers southeastern New Mexico and much of West Texas. This paper will concentrate on the New Mexico portion of the Basin in an effort to provide the engineer with a basic review of the geological features and reservoir characteristics of the area. There are many subprovinces in this large basin which affected the formation of reservoir rock and the accumulation of hydrocarbons. An understanding of the origin of these subprovinces should greatly aid the engineer's efforts to develop new reserves and improve recovery from existing reservoirs. Shown in Figure 1 are the major geological features (or subprovinces) of the area. These are the Central Basin Platform, the Delaware Basin, Eddy Shelf, Northwest Shelf and Pedernal Land Mass. All but the Pedernal Land Mass are major producing areas. Each has its own structural and depositional characteristics which resulted in distinct reservoir properties and hydrocarbon accumulation. Each of the features will be discussed in some detail.

The Pitchfork Ranch Field is located in southwestern Lea County, New Mexico, about 17 miles northwest of Jal and about 110 miles northwest of Midland. See Figure I. Figure II is a composite electric type log indicating the various pay zones of the Pitchfork Ranch Field. Figure III shows the area1 distribution of the field and its general structure. Figure IV is a net isopach of the Morrow "C" Sand, the main pay zone in the field.

1- Raw Materials: A brief discussion of basic raw materials for glass reinforced tubular goods, mechanisms of polymerization and comparative properties of different types of resins. 2- Designing Filament Wound Structure: How glass fiber and resin can be utilized to obtain maximum strength and how design can be varied to obtain best performance depending on end use stress conditions. 3- Testing and Rating: Accelerated laboratory test method to project performance ratings and correlation with field test data. 4- Case Histories: Typical installations where reinforced plastic piping has been used to overcome corrosion problems in petroleum producing activities.

The development and application of a unique series of environmentally friendly microemulsion additives over the past four years has shown success in thousands of oil and gas wells in the U.S. and Canada. Microemulsions, while not new fundamentally, have been formulated to become stable nanostructures dispersed in either oil or water based fluids so that they do not actively dilute and activate upon contact with a surface, such as reservoir rock or other targeted liquid or solid, thereby providing via ultra-low interfacial tension, an optimum mechanism for significantly improved efficiency for dewatering of coal-bed methane wells; formation damage prevention or removal in fracturing or acidizing systems; H2S mitigation in a variety of remedial pumping operations including stimulation, wellbore and fluid invasion protection for drilling fluids, particularly in underbalanced conditions.Specific laboratory and scientific background information, with numerous case histories from around the Western and Eastern U.S. oil and gas fields will be presented for each of the categories above. They will demonstrate process enhancement using microemulsion additives both in standalone as well as in providing improvements to other regularly used technologies. Comparisons showing their successful use versus current technologies will be made.

Tests were conducted to evaluate the plugging mechanisms of metallic screens after cleaning up the filtercake developed on an unconsolidated core by two exiting drill-in fluids (DIF"s). Two simulated drill solids, clay or 75-mm reservoir sand were added as drill solids to these DIF"s. Metallic screens were used to simulate the sand control device. The DIF's tested included a sized-calcium carbonate (SCC) and a sized-salt (SS). The presence of the drill solids was found to affect the particle size distribution as well as the mean size (D50) of the particles of the bridging and weighting material (BWM) and loss control material (LCM) of the DIF"s. On the basis of the observations, it can be concluded that SCC filtercakes tended to result in minimum dislodging pressure (MDP), leading to higher regained-flow capacity and lower plugging of the screen. In contrast, SS filtercakes required high MDP, decreasing the regained-flow capacity highly and causing severe plugging of the screens.

The most important objectives of the laboratory work presented here were aimed at investigating how the chemical composition of the natural formation brine and different minerals present in the carbonate formations interact with CO2 injection under supercritical conditions. The study focused on the alteration of the petrophysical properties of the carbonate reservoir rocks resulting from the interaction of rock/ formation brine and injected CO2. Conventional and Neutron Magnetic Resonance (NMR) core analyses indicated that that low pore volume of CO2 injection caused substantial reduction in the petropysical properties of the samples, permeability and porosity. The permeability was reduced by about 50% and the pore volume and porosity by about 25%. In contrast, the injection of high pore volume of CO2 showed a slight increase in the petrophysical properties. The static interaction between supercritical CO2 and natural formation brine showed a precipitate formed primarily by calcite, dolomite, gypsum, halite and other mineral salts.

The common beam and sucker rod pumping unit is old technology yet it continues to be part ofthe most popular artificial lift system in use today for several good reasons. A few of the more important are: It is a simple mechanical mechanism that is easily understood and therefore easy to keep in good repair. It is a highly efficient part of the beam and sucker rod artificial lift system. It can be very ruggedly built resulting in a long useful life. Because the surface unit has a history of being relatively trouble free, there is generally little attention given to providing really good preventive maintenance to this equipment. Rather the attention is given to some other part of the system that requires more frequent repair. As a result, when a failure occurs in the pumping unit, it is often a surprise and expensive. Exceptional maintenance can add years to the life of the machinery and reduce operating cost. This paper is intended to supplement your existing preventive maintenance program by developing a good understanding of the really important maintenance requirements for a beam pumping unit.

The return to a university for graduate studies after an engineer has begun practice in the petroleum industry is discussed. Some
factors motivating advanced studies are given. Several general programs are outlined and described. Justification of the time and
effort required for study leading to a master's degree for both engineer and employer is considered. This presentation concludes that graduate studies are not desirable for many, perhaps even most practicing petroleum engineers; but some engineers gain professionally and personally from such studies.

It is important that oil wells be produced at their maximum permissible rate because of the greater income generated, lower lifting costs per barrel, quick return of investment, and the larger oil reserve of a top allowable well. It is the purpose of this paper to show a determination of the magnitude and cause of skin effect and a consideration of the factors in the Darcy Formula may be used to predict successfully the results of workover operations.

Production equipment failures in beam pumped wells are an everyday expense in the oil field. Minimizing repeated or unnecessary failures caused by improper design handling and metallurgy directly reduces the operating expense of any oil company or operator. As the industry downsizes its work force, innovative ways of maintaining or reducing well service costs are becoming more and more necessary. This paper presents a guide to various causes to common failures which are applicable in a variety of service conditions: sour/sweet, shallow/deep and high/low production volumes. This paper is aimed at decreasing over-dependence on technologically advanced equipment, complicated databases and the intensive training needed to assist an inexperienced technician or operator in identifying and diagnosing the root causes of common equipment failures. The guide was developed by personnel from a West Texas operating company and is based upon their five-year study.

Results of work performed to determine the degree of cement sheath shattering that occurs during perforation indicate the application potential of lightweight "lead" cements as "perforating" cements. Four lightweight cement candidate blends were tested and compared to conventional, normal density, tail cement. A 7 in. OD, 23 lb/ft J-55 casing test fixture was used. The formation was simulated by a piece of tubing 10.75 in. OD by 0.188 in. wall. The 10 in. thin wall tubing is not a component of normal well completions; it served to act as a simulated formation to hold cement in place. The cement was perforated with 0.42-in. dia. perforations, 90" phasing, four shots per foot (spf) with 22 gm charges placed in each test fixture. The test procedure was specifically designed to duplicate typical field conditions in the Midland, Texas, area, and to determine the amount of cement shattering that occurred while perforating. Test fixtures were sectioned after perforating, examined for cement sheath damage, and photographed.

During the course of any acidizing treatment, a certain amount of iron is dissolved by action of the acid upon treating lines, equipment, downhole tubular goods and iron containing minerals present within the formation. Upon spending of the acid, this iron may precipitate as insoluble gelatinous ferric hydroxide. This precipitate is an effective plugging agent which damages permeability and restricts oil and gas production. In order to prevent iron precipitation, stabilizers are routinely added to the treating acid. These stabilizers form soluble chelates or complexes with iron and prevent precipitation of ferric hydroxide. This paper describes the advantages and limitations of the various commonly used iron stabilizing agents. Guidelines are presented for selecting the proper additive and determining the concentration needed for iron control. Well conditions, as they relate to the need for iron stabilizing agents, are also discussed.

Deposition of gypsum is the source of some of the most severe production and water injection problems in certain areas. Considerable progress has been made recently in the field of gyp (CaSO4 * 2H2O) removal and prevention in oilfield applications. This paper shows the results of a comprehensive laboratory and field evaluation of various types of scale removal methods which may be classified as: 1) converters, 2) disintegrators and 3) solvents. Also, a laboratory comparison of the various types of liquid scale inhibitors and a discussion of various placement techniques for field application is included.