This paper presents the permissible envelope, which accounts for both positive and negative gearbox torque rating. Permissible envelopes enable more complete definition of acceptable pumping unit rod loads than has been available in the past.

One purpose of obtaining a surface dynamometer card is to learn how well the downhole pump is functioning. Several methods have been used to develop a finite mathematical model of a simplified pumping system to predict or evaluate pump behavior given dynamometer polished rod loads and displacement at the surface. The purpose of these methods was to develop a computerized method of analyzing surface dynamometer cards. The alternative is to evaluate the card by visual inspection, which is very subjective, requires a skilled analyst, and yields results which are strictly qualitative in nature. The work done by Gibbs, in particular, has apparently been successful, considering the expense involved in using or obtaining one of his patented programs.' Otler than the expense, the programs are generally designed for applications with main frame computers, and the development of the equations used in the programs seems to have been left purposefully ambiguous. The purpose of this paper is to present a relatively comprehensive and user-friendly program for use with micro-computers based on a finite difference method initially developed by Roy Knapp at the University of Kansas.

Once upon a time there was a land where petroleum and natural gas were abundant. In this land, petroleum and natural gas were both the most convenient fuels and at the same time the least expensive fuels. The people were reasonably happy and the economy prospered because of the abundance of economical fuel and other reasons. The fuel demand grew and grew for this prosperous economy, until the reserves of domestic petroleum and natural gas were inadequate to supply the needs of the economy. For a while, oil was imported without great financial or political difficulty, and few people worried about the future. Then imported oil was denied the people temporarily, its price increased rapidly, and many people became very concerned.

Most petroleum engineers, operating personnel, and management personnel are familiar with the role of banks in commercial lending. Banks have long been involved in the financing of development drilling, workovers, secondary-recovery projects, gasoline plants, acquisitions and many other facets of the oil industry. Another role- that may be new to many operating personnel is the role of bank trust departments in management and operation of oil and gas properties. This is a relatively new segment of the century-old petroleum industry. In the last several years, numerous banks in oil- and gas-producing areas have employed oil-industry specialists to join their trust departments to provide the expertise needed to manage this type of asset. One of the first professional technical persons in this role was a petroleum engineer employed by First National Bank in Dallas about 20 years ago. The Trust Oil Department staff now includes five petroleum engineers, three petroleum landmen, and 19 other land, accounting, and technical-support personnel. These persons are involved in virtually all aspects of management of mineral properties in 26 states. Due to First National's location in the largest oil producing state, the estates of independent oil men provide a large portion of the trust assets, and these estates rate among the Bank's most important business. Approximately 20 percent of the estates and trusts which the bank serves in a fiduciary capacity own some type of mineral interest. Types of ownership include undeveloped mineral interests, royalty interests, outside-operated working interests, and bank-operated working interests. Revenue to the beneficiaries of these trusts and estates is approximately $35,000,000 annually. This revenue exceeds that of many independent oil companies operating in the state of Texas. The fiduciary's interest in the operation of such properties is indicated by the fact that in working interests alone, my bank represents the ownership of 4,500 barrels of oil per day and 45,000 MCF of gas per day. Thus, the bank is a not-so-small "small oil company" when co-owner approvals of development projects, drilling wells, secondary recovery projects, etc. are required. In properties where the bank is a non-operating working interest owner, it acts like what may be described in a company as a joint-interest manager. In management of bank-operated properties, the engineer may serve as a combination reservoir engineer, geological, production and drilling engineer, or he may employ outside consultants when appropriate.

Before exiting the oil patch, I want to provide a partial list of the tools that helped me anticipate, find, define and suggest solutions to petroleum production problems. Educators tell us that if we can fully define a problem, the solution usually becomes readily apparent.

Current interest in miscible enhanced oil recovery methods has led to the use of compositional simulators to understand and predict the performance of such processes. Fluid property considerations are highly important from two standpoints: 1. An essential part of such a simulator is a means of predicting the complex phase equilibria likely to be encountered in such EOR processes. While reliable equations of state have been developed to calculate phase behavior in these processes, most often parameter adjustments are required to properly describe the COZ-reservoir oil systems. These adjustments require experimental data on systems of interest. 2. The evaluation of the physics required in such a simulator depends upon an understanding of the fluid properties that will be encountered. The relative importance of viscous fingering, gravity override, physical dispersion and low interfacial tension effects must be assessed through interpretation of laboratory CO2 coreflood and pilot field studies. This requires an understanding of the phase equilibria encountered in such processes and the ability to make reliable predictions.

Long term chemical and physical performance of aliphatic amine cured fiberglass Tubulars in high pressure super critical application of CO2 in both cyclic and static conditions have been investigated. No physical or chemical degradation was detected at the selected test condition of 2300 PSI and 120_F of carbon dioxide in cyclic or static conditions. Further analysis suggests a slow rate of CO2 penetration into the amine cured epoxy laminate. The failure mechanism model developed and presented here suggest a predictable failure based on stress due to pressure and temperature. The verification of the model presented paves the way for major simplification and cost reduction potentials in future construction and extension of a CO2 WAG Piping Systems.

The Langlie Mattix Pool is located in southeast Lea County, New Mexico, as shown in Fig. 1, and contains approximately 1200 wells drilled on 60,000 acres. Discovered some 30 years ago, it is now essentially depleted of primary oil. Waterflood potential appears excellent and there are at present 10 water injection projects in operation and several more in various stages of development. One of the earliest of these is the Woolworth Unit, operated by Amerada Petroleum Corporation. The Woolworth Unit was formed in late 1962 and began pilot water injection in early 1963. A pilot project was considered essential at that time for the following reasons: (1) The unknown floodability of the reservoir. (2) The lack of reservoir definition (virtually no logs or core analyses). (3) The questionable condition of well bores (open holes shot with nitroglycerine). (4) The nearness of the injection interval to an overlying gas reservoir. The operation of the pilot and unit, performance to date under water injection, and related topics are discussed in the following sections.

August 17, 2006 marked the 10th Anniversary of the Pioneer Natural Resources, Preston Spraberry Unit (PSU) "Best Practices" Failure Reduction Program. This 10 year partnership between Pioneer Natural Resources, Flexbar Inc., Norris Rods, Tommy White Supply and Kel-Tech has resulted in significant reductions in downhole failures and savings in operational costs for Pioneer Natural Resources. The 10 year performance (FPWPY) for this 150 well, PSU "Best Practices" program has resulted in a 94 % reduction in Tubing Leaks, 75 % reduction in Rod Failures and an 80 % reduction in Pump Failures. The 10 year performance (Dollars Saved) for this PSU "Best Practices" 150 well project is estimated at $17.9 million utilizing the 2006 failure costs of $16,000 per Tubing Leak, $9,000 per Rod Failure and $8,000 per Pump Failure. This 10 year savings represents an average of $1.8 Million per year for this 150 well failure reduction program

During the past two and a half years, a new fracturing technique has been developed to selectively place proppant across a well's producing interval. The new technique, termed "pipelining," has been employed in hundreds of wells in the Permian and Delaware basins. This technique utilizes high differential viscosity to selectively place high concentrations of proppant across the well's producing zone. This technique involves specialized design and iterative modeling procedures. In the paper, we will discuss the ongoing improvement of the "pipeline" fracture design and present numerous case histories of various sand members of the Delaware formation throughout Southeastern New Mexico as well as other producing horizons in the Permian Basin. The authors feel that the "pipeline" fracture technique, combined with intense quality control and aggressive forced closure, greatly enhances the ability to selectively place proppant in the pay zone and allows for highly conductive propped fractures for much greater lengths than were heretofore felt possible.

The generally accepted methods of pumping unit selection usually are satisfactory in obtaining the correct sizes of pumping units; however, the average design conditions do not take into consideration such factors as down hole friction, fluid with a gravity greater than one, out of counter-balance conditions, and many others. Each step in the procedure of proper selection is discussed, and the pitfalls which may and can occur are pointed out for examples.

Writing is the keystone of business achievement, yet most of us give little thought to our writing habits. Hurried businessmen are trying to read faster, but few are trying to write simpler. This paper presents a "New Way" for technical writing, based on plain talk and the reader's point of view. Typical examples of rambling and wordy technical writing are shown, together with suggested revisions for easier reading. Checklists for better letters and reports are included, as well as a bibliography of practical references

In recent years salt water disposal has become an integral part of the planning and cost of lease operation in the industry. Because disposal is an additional expense, disposal systems need to be properly designed, equipped and maintained to keep the operating costs reasonable. An efficient and economical disposal system is no "accident"; it should be designed in detail and adequately supervised during installation. Because of the corrosive nature of oil-field waters, the proper selection of materials for the system is very important in keeping the initial cost and replacement costs at a minimum. Continual supervision by experienced personnel is essential in order to insure continuous and efficient operation of the system throughout the life of an oil field.

Know-how about things mechanical is a part of our national character. The knack of making complicated machinery work is an American tradition. Good old "Yankee Ingenuity" applied to machines has produced countless achievements from the steamboat of yesteryear to Apollo 17 of today. Equally outstanding but not so well known examples of this native ability of ours are the stationary gas engines and reciprocating compressors found in the oil and gas industry. These machines, in various forms, have been around for well over 50 years and it is not at all uncommon to find 30-year-old installations still operating at full capacity, day in and day out. They range from small units of a few horsepower to giants of several thousand horsepower. These machines have served the oil and gas industry exceptionally well for a long time under extreme service conditions. Their durability and efficient performance certainly are a tribute to their designers and builders, and to the people who have operated and maintained them through the years. The purpose of this paper is to take a critical look at the "current state of the art" concerning the operation and maintenance of these machines and to comment in general on the subject of preventive maintenance in an effort to put some of the many aspects in proper perspective. The topic is far too broad and complex to cover in specific terms and each individual installation has many unique features that require special consideration. Therefore, this review will only attempt to point out certain guidelines and critical requirements that in the writer's opinion a sound preventive maintenance program should have. Then each location can be examined to determine if present methods have any deficiencies that should be changed.

This paper discusses the advanced planning required in wellhead design as a result of the many combinations of casings and tubings utilized in multiple completions.

The World War II Allied assault on the beaches of Normandy is described by Corneluis Ryan in The Longest Day, a book in which the author provides a detailed record of one day in history. It would be a mistake, however, to think that the story of the Normandy Invasion is completely told by relating only events of that single day. Planning for June 6, 1944 began years before, and nothing that happened on that day was more important than the efforts spent in planning the operation. Not only a military operation, but any major undertaking demands a detailed, well thought-out plan to achieve success, especially when the undertaking involves safety of personnel, considerable financial investment, and coordinated efforts of many people. Drilling a well is just such an undertaking, and a plan for drilling the well provides the drilling manager, the person with ultimate responsibility at the wellsite, exactly what a battle plan gives an army general -- a orderly and detailed program for successful completion of his mission. This paper will discuss in detail each of the components of a drill plan. In the case of a drilling project, success is measured by reaching total depth without exposing personnel to unnecessary hazards, while reducing total drilling days, keeping non-drilling days at a minimum and controlling overall costs. Simply stated the benefits of effective planning are fourfold: * Safety * Economy * Evaluation * Formation Protection

Problems inherent in drilling horizontally make planning particularly critical in such projects. Reaction time for the ever-changing formation are much shorter than when drilling a conventional directional well. A medium radius horizontal well with build rates ranging from 15deg/100 ft to 30-deg/100 ft can go awry quickly. This paper discusses the specific information required to produce a detailed well plan that will help ensure a successful horizontal project, such as build rates, horizontal extensions, formation evaluation, drillstring components, pump restrictions and drilling fluid requirements. Several medium radius case histories are described briefly to illustrate the importance of planning.

The adverse effects of pulsations on compressor and pumping stations have long been recognized by industry if not totally understood. With the development of the SGA Compressor System Analog, a means is available to accurately predict piping pulsation levels and shaking forces and to optimize piping design from the standpoint of compressor efficiency. Experience has shown, however, that criteria based upon pulsation levels alone, or even upon pipe vibration levels, are inadequate for the design of reliable piping systems. To overcome such limitations, therefore, prediction techniques have been evolved to completely describe piping integrity in terms of vibratory stresses produced by the dynamic pulsation forces and static loading due to thermal expansion, pressurization, and bolt-up. These plant design techniques, used in conjunction with analog data, provide a broad spectrum of design capabilities from plant layout to detailed component design.

Plastic coatings have become a vital part of the Oil Industry for protection against corrosion in tubular goods, oil field storage tanks, and miscellaneous equipment. And for the protection against paraffin clogged flow lines and tubing. With oil field equipment being as expensive as it is and the need for the production of more oil ever present, it is easy to see the feasibility of a coating that will offer protection and prolong the life of this equipment twice it's normal life span. Giving complete satisfaction in performance.

Corrosion, as we speak of It, may be defined as an eating away of a material and it falls into two general categories: chemical attack, as in the action of an acid or oxygen on a metal, and electrochemical attack in which a chemical change takes place, dependent on the flow of an electrical current. This is also known as galvanic corrosion. Chemical corrosion results when a metal is placed in a reactive environment. This may be controlled by either changing the nature of the environment. This may be controlled by either changing the nature of the environment or insulating the metal from the environment. Usually in oil and gas corrosion we attempt the latter, either by use of inhibitors (chemical coating agents) or by the more permanent plastic coatings. In combating environmental attack, the insulating material must be completely inert to the environment and incapable of being permeated by that environment.

Many forms of artificial lift have been designed to deliquify gas wells. Plunger Lift is one form, utilizing the wells natural reservoir pressure as the prime energy source for removing the liquids from the bottom of the well bore. Intermittent operation of a motor valve installed on the tubing, allows fluid to be lifted to the surface, utilizing the free running plunger as an interface between liquids accumulated in the bottom of the well and the stored gas in the annulus. There are many variations of plunger lift employing multiple motor valves and many different sub-surface mechanical tubular arrangements. Chamber Lift is another form of artificial lift extending from Gas Lift. Combinations of Gas Lift and Plunger Lift have been used in the past and the technique described within is an extension of those methods.

Data acquired at various wells will be used to correlate the construction features of different types of plungers with their fall velocity. Some construction features cause a plunger to fall rapidly, while other features cause the plunger to have a slower fall velocity. Well conditions (gas flow rate and pressure) have a significant impact on plunger fall velocity. Published fall velocities can be used for each plunger type but may not be accurate for all wells, because fall velocity is impacted by many parameters. By accurately measuring the plunger fall velocity, the proper shut-in time for the plunger lift installation can be determined. The knowledge of how various parameters impact plunger fall velocity allows the operator to ensure that the plunger has reached the bottom of the tubing by the end of the shut-in period. Setting the well's controller to have the shortest possible shut-in time can maximize oil and gas production from the plunger lift well.

A new method for calculating plunger pump leakage in rod pumped wells is introduced. This method involves calculating a velocity profile for an annulus with the inner wall moving parallel to the outer wall. An average velocity is determined for the annular fluid flow, which in turn is used to calculate the fluid slippage. Eccentricity is also considered in the slippage calculation method. The results are evaluated against the historical field data and compare favorably to recent testing for smaller plunger clearances. Work remains to be done at larger clearances. A formula for calculating viscous plunger drag is also introduced.

Controlling plunger-lift wells has always proven tricky, if not outright difficult. The advent of electronic controls dramatically improved the success of plunger-lift applications. The reliability of controls along with the varied programs available has made the job easier, and therefore improved the overall operation. Wells never before considered candidates are now regularly employing plunger-lift. While the reliability and flexibility of equipment has improved, most plunger-lift wells are still operated at less than optimum levels of productivity. Today's busy well operators have less time available, making optimization difficult. Utilizing telemetry, along with the Auto-Cycle algorithm, has shown dramatic increases in production, eliminated down time, and maximized the pumper's time. It also serves to provide real time production and management data. This paper looks at several fields where operators have maximized their time, and increased their production through field automation.

The development of the Eumont gas play in Lea County, New Mexico created unacceptably high operating costs associated with gas well production. Two major issues were economically producing low pressure gas wells (1, 5-2 psi/l00 feet) with low connate water production and proppant production. The first choice for artificial lift once loadup occurred was beam pumps. Sand production and low fluid volumes however forced a paradigm shift to evaluate plunger lift as an alternative based on the low fluid volumes and low bottom hole pressures. The end result has reduced operating costs by over 70% in the areas that plunger lift has become the primary artificial lift method and reduced the lease expense per BOE by 25% over the 2-1/2 year implementation period. This paper discusses the steps taken to apply basic plunger lift concepts and progresses to the current plunger lift system that incorporates annular flow to minimize bottom hole pressure; therefore maximizing production. Evidence will be presented to validate that switching from beam pump to plunger lift has on average increased production. integrating this "new found" technology on high GLR oil wells has been beneficial as well.