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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.

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.

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.

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.

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.

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.

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.

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.

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.

To unload liquid from a conventional plunger lift well requires that sufficient pressure builds during the shut-in time period as the plunger falls through gas, liquid and then rests at bottom on the bumper spring. Industry rule-of-thumb criteria to determine when the well should be opened to unload the liquid include building casing pressure, CP, to 1 _ times the line pressure, LP, or also using the tubing pressure, TP, in the Load Factor (CP-TP)/(CP-LP) calculation to be less than one-half(_).

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.

A project was undertaken to utilize plunger lift in wells with abnormally low bottom hole pressures. This was accomplished through the use of coiled tubing for side-string injection (see schematic). This application has a wide range of applicability for high water cut low-pressure reservoirs.

It is the purpose of this paper to provide some assistance whether or not plunger lift is an economically viable alternative production method for specific wells. An evaluation spread sheet has been developed to assist in determining whether or not a rod pumped well is a likely candidate for plunger lift. The paper seeks to describe the assumptions and derivations of the equations in the spread sheet to provide a through understanding of the methods used in developing the spread sheet.

With the increase of horizontal drilling for oil and natural gas, the problem of keeping liquids removed from the wellbore becomes more evident. Several methods of artificial lift have been implemented to resolve this problem with varying results. This paper will discuss the use of plunger lift to resolve this problem and the mechanical requirements associated with plunger lift.

Plunger lift Technology has been with us for decades, no one knows for sure who first developed the idea, but we have seen the technology evolve from a rough guessing game to a near absolute science. The introduction of the electronic controller has brought the technology further than any other single development. This paper will cover one of the many areas, where electronics have allowed us to refine the technology

We could easily think of Plunger Lift as the ultimate in long stroke pumping. This is true because we have an expanding piston operating the full length of standard A. P. I. tubing without direct connection with surface mechanical energy. Rather than using the term "Pumping," we might think of Plunger Lift as a refinement of gas lift. plunger Lift operations are a form of intermitting gas lift, gas lift here referring to both natural flow and where additional gas is being injected, with the plunger constituting a seal between well liquids and propulsion gas.

Plunger Lift operations are oftentimes not optimized due to lack of knowledge of plunger location and changes in tubing pressures, casing pressures and bottomhole pressures. Monitoring the plunger location in the tubing helps the operator (or controller) to optimize the production of liquid and gas from the well. In low liquid volume wells, the plunger position can be tracked from the surface by monitoring acoustic signals generated as the plunger falls down the tubing. When the plunger falls through a tubing collar recess, an acoustic pulse is generated.

Fluctuating line pressures and liquid loading are a bad combination and in the Moxa Arch field in Southwestern Wyoming they presented the operator and Weatherford Artificial Lift Systems with a perplexing problem. Can conventional plunger lift be effective in an area with severe line pressure fluctuations? Can it provide for efficient removal of accumulated fluids while reducing or eliminating the need to vent the well and minimizing the time that the lease operator has to spend at the well location?

The advent of "smart" microprocessor based plunger lift controllers has produces a renewed interest in the application of plunger lift to remove fluid from both oil and gas wells. While a great deal of information regarding the economics of plunger lift installations and operations exist there is little information available to assist in the design and evaluation of new plunger lift applications. This paper seeks to provide an approach to determining the operational feasibility of plunger lift operations in advance of equipment installation.

With today's economics in the oilfield, many operators are searching for ways to cut lift costs. Plunger lift is often considered. However, if it is projected that a particular well does not have sufficient gas to operate a plunger, this means of artificial lift is no longer considered. For instance, if a particular well shows to be 10 MCF per day below operating requirements, an operator may spend upwards of $50,000.00 to rod pump this well. An alternative would be to add 10 MCF per day to this well through gas injection. Many operators have high pressure gas available without realizing.

After decades of trial and error, and frustration, plunger-lift finally has become widely accepted as a legitimate solution to producing many wells. As the experience level has increased, so has the success. As the equipment has been improved, so have the applications. This paper is to describe an application, coupled with new technology that is allowing producers to use plunger-lift systems on wells never before possible. The limiting factor for most plunger-lift wells is gas. It is now possible to take advantage of the low lifting costs of plungers on some of these wells.

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.