This article examines some causes of rod failure and explains material selection, running and pulling practices.

Producing hydrocarbons from the lower Delaware Formation in SE New Mexico and West Texas is often associated with a high water production. In the Matthews Field in West Texas, an operator was encountering water production of over 600 bbls per day from the prior treated wells. Modifying the stimulation techniques and processes were chosen in an attempt to improve the production results. Multiple stage treatments using coiled tubing with selective placement controls and reduced rates were performed to lower the fracture height growth in an attempt to reduce water production. This method included using conventional fracturing fluids, specialized coiled tubing perforating and controlled fracturing placement, and a relative permeability modifier capable of modifying the relative permeability by coating the formation rock, thereby reducing the potential for water production. This paper will detail how these operations were performed.

The main purpose in the treatment of the Devonian formation is to successfully place the proppant strategically to produce as little non-hydrocarbon fluid as possible. In the Roepke Field in West Texas (Crane County), an operator was entering his first newly drilled well in the area. Difficulties in the completion for an offset operator included high treating pressures resulting in shortened pump schedules and low fracture conductivity. Issues for this operator included proper log analysis, perforating schemes, well-bore mechanics, and the main stimulation treatment design. After discussions with the service company, an alternative method of fracture treatment was successfully tried and adopted to solve these problems. This method included designing the treatment with calculated rock properties in a 3-D fracturing model pumping a high permeability regain fracturing fluid via tubing, which doubled as a temporary production string. This paper will detail how this problem was successfully addressed.

The paper will discuss an innovative stimulation technique performed on several open hole horizontal San Andres wells in Dawson and Gaines County, TX. Stimulation objectives will be outlined and explained along with supporting well production information. The paper will also compare this completion technique with several other horizontal stimulation techniques performed in the recent history of this field.

Understanding the fundamental advantages and disadvantages for running a Top Hold Down Pump compared to the advantages and disadvantages of running a Bottom Hold Down Pump.What type of well conditions and parameters to consider when deciding on a Top Hold Down Pump or Bottom Hold Down Pump.

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Augue, in eu scelerisque diam a turpis eu ultricies in ut. Ut rhoncus etiam, porttitor, porta lundium, adipiscing lorem tristique amet, pulvinar magna, eros. Aliquet pid augue dolor eu vel nunc natoque, montes urna eros, mus tristique sociis, integer tortor! Rhoncus, integer augue parturient augue mattis aliquam! Magnis et quis diam mattis duis purus ac rhoncus nascetur ridiculus turpis, lorem porttitor lacus eu montes odio eros, nunc cum in, et nisi ultricies, parturient, tristique ut, turpis cursus. Tempor! Massa pulvinar. Porta ac porttitor? Magna! Pid magna. Purus, aenean lundium augue vel ac mauris porttitor dapibus enim integer augue pulvinar, augue placerat, lorem natoque amet porttitor lacus scelerisque, sed lectus mauris magna lorem sed, rhoncus integer ac? Aliquet, ac sed.

A computer program has been developed which permits torque calculations in a much simpler and much accurate manner than previously presented in API publications. This is accomplished by using a highly accurate digitizing technique to input the necessary number of points from the dynamometer card. The proposed technique improves the accuracy of the data over manual input and allows a much greater number of points to be used for subsequent analysis. The program can handle all pumping unit geometries and calculates all the parameters for a complete analysis of the pumping unit: PRHP, PPRL, MPRL, PT, etc. The instantaneous torques are plotted vs. crank angle. The program also evaluates the counterbalancing of the unit by calculating the Cyclic Load Factor for actual conditions. The author proposes a new technique to find the maximum counterbalance moment needed for ideal counterbalancing. The theoretically sound procedure seeks that counterbalance moment which results in the least value conditions. of Cyclic Load Factor for the given This approach ensures the minimum of prime mover power requirements, installations, and can reduce the power consumption of existing thus improving the economy of sucker rod pumping.

Manufacturers are constantly being asked to furnish special combinations of stroke length, beam sizes and other structural modifications to meet the particular requirements of those responsible for the application of pumping units. These special demands are often made without due consideration of their effect on the loading of the unit gear reducer and prime mover. Torque factors which were made available through the workings of API committees have not been used as much as they should be; if they were, some of the special arrangements would not be requested. The proper use of would make it evident that such changes could easily overload the gear reducers. Although the use of torque factors was started approximately 15 years ago, their general adoption has been slow. Producers have not demanded and manufacturers have not furnished them because of the trouble in calculating them.

In order to clarify the present discussion, it is thought wise to review briefly the discussion and demonstration of The dynagraph animator, to help you visualize the properties of sucker rods, and the significance of the dynagraph. The dynagraph of an oil well is no more than a graphical record of force recorded against a distance from some starting point. We usually consider the lowest point in the polished rod travel, which is the beginning of the point. The dynamometer is usually supplied with a vibrating device whereby the time element be separately recorded with respect to the starting point.

The Oil and Gas Industry is benefiting from development and use of improved predictive computer programs that now utilize several friction defaults. These predictive programs are more capable of predicting surface and downhole rod pumping conditions. The need for improved predictive accuracy is requiring program users to adopt improved estimates of downstroke friction to model downhole pumping conditions. Lack of improved estimates of downstroke friction has resulted in program users accepting and designing with current friction defaults that may result in results different than actual downhole pumping conditions. This paper develops a method of estimating total downstroke friction from existing dynamometer analysis. Use of this method in producing fields with similar operating conditions will provide improved estimates of total downstroke friction. A better understanding of the magnitude of total downstroke friction will result in improved friction defaults. Improved friction defaults will result in more effective designs of rodstrings and artificial lift systems.

Given the dynamic nature of production for an oil well and the magnitude of the lifting cost, there are few opportunities with a better payoff than reviewing the total rod system designi-2. However, with the current trend of increased well count and responsibility for the engineer and field personnel, it is often one of the things for which there is never enough time. Even with a shelf full of technical manuals, books, forms, and programs to calculate everything from pumping unit and rod loads to sheave and belt sizing, designing all of the components of the rod system is a very time-consuming operation. " TOTAL ROD " system design is a LOTUS 123 n based template for efficient rod system design and management. It allows numerous combinations of all operating conditions to be considered simultaneously in one program. Calculations are performed for: API RP 11L loads s for Conventional, Mark II, Air Balance, and C M I units based on conventional RPllL tables (or based on tables generated by the wave equation model 4 of Shell Oil Company), sinker bars, producing and static bottom hole pressures based on fluid levels 5 corrected for gas in fluid or foam, production capacity based on producing and static pressures and reservoir drive, belt and sheave sizes, daily pump time, electrical cost, mud anchor and gas anchor sizes and placement, and total system efficiency. "TOTAL ROD" allows multiple runs to be considered in detail and in a fraction of the time. The spreadsheet format of LOTUS 123 presents the runs side by side and provides graphics and data management capabilities.

This paper presents the results of a Total System Cost Comparison program between Electric Submersible Pump's (ESP"s) and Beam Lift Pumps that are typical within Amoco's northern Permian Basin operating areas. This program calculates a common variable of, .VBFPD. for Total System Cost and Operating and Maintenance Cost. This common variable may be used to help the operator make the best decision regarding economics, on which type lift to use. The calculation takes into account all equipment cost, all installation cost. all repair cost and all operating cost for a typical 10 year period of time at a specified depth and volume. Also considered in calculating the repair cost for a 10 year period of time is the type failures, cost per type failure and frequency of these failures that are typical within these operating areas.

Major advances in the measurement of extremely small amounts of radiation make the use of radioactive isotopes as a tracing material in petroleum reservoirs practical. Isotopes, Inc. has developed equipment capable of extremely low level techniques which, together with a number of low cost radioactive isotopes, make possible many useful applications in reservoir engineering. By introducing radioisotopes in the injection wells with the injected fluids it is possible to "tag" the injected fluid and, by analyzing produced water or gas, to trace the movement of the injected fluid throughout the reservoir. Directional permeability may be identified early in the lift of the project so that steps can be taken to maximize recovery efficiency.

With the exponential growth that our industry has experienced, Pioneer Natural Resources needed additional training for their new hires concerning basic rod pump design and how the rod pump works in a normal pumping system. With PNR's vendor base, pumpers, technicians and management, we worked together to develop this training presentation. Our discussions lead us to the issue of tagging wells and the effects it has on the entire pumping system. This team realized that this school would be beneficial to all field employees, not just new hires.

Plunger lift has become a very popular and economical artificial lift alternative, especially in high GLR gas and oil wells. Success in plunger lift systems depends on proper candidate identification, good wellbore mechanical integrity, and the effectiveness of the production or lease operator. This paper will focus on the production operator, and describe the basic principles necessary for effective training and the sound operation of a plunger lift system. In many instances the plunger controller is the main focus of training. However, a clear understanding of why a plunger system is needed, the proper operating parameters, and the relationship of IPR curves and unloading rates are more important to effective operator training. If an operator does not clearly understand these principles, a plunger system is unlikely to be operated at peak efficiency. Knowing how a gas well loads up, what options exist to remedy this problem, and what the remedies actually accomplish are necessary to maximize efficiency and profits. This paper describes foundational principles required to understand and operate a plunger lift system, and explains some common misconceptions. Also included are a description of plunger parts that need to be maintained, a parts "survival kit", a description of some common problems to plunger operation, and a basic trouble-shooting chart. With this information an operator will be able to keep a plunger system running efficiently in order to maximize well production.

As the search for new gas supplies intensifies, deeper reservoirs are being investigated. The following describes the design, testing, and difficulties encountered in transient pressure analysis in a high pressure, low permeability gas well. The conclusions drawn from the test will also be discussed. Transient pressure testing was selected as the most timely method to describe the reservoir. The pseudo-pressure technique was applied to the data obtained. The subject well, Emma Lou Gas Unit 1, Well No. 1, was completed from 22,156 ft to 22,240 ft in the Puckett West Bend Field, Pecos County, Texas. The initial reservoir pressure was greater than 18,000 psi, and the reservoir temperature was in excess of 360 F. Due to the pressure and temperature in this well being beyond any empirical relationships, the compressibility and viscosity data were obtained from, the Peng Robinson Equation of State. All test data was gathered at the wellhead, and the bottom-hole conditions were calculated from the Cullender and Smith Sandface Pressure Method. Due to a rapid decline in pressure, a multi-rate test was initiated. No conclusive evidence of a reservoir boundary was seen during the testing. However, due to the low kh and deliverability, additional drilling was not undertaken. Even though the test was performed in a limited time and without laboratory analysis of fluid and formation properties, well performance to date has supported the reservoir description from the drawdown and multi-rate tests.

Treating is simply a procedure that has been devised to separate crude oil from the water and foreign material produced from the reservoir. In treating a wellstream, the treater "breaks" the emulsion and separates the oil from the water, sand, and other sediment produced with it.

Two simple aids for improving emulsion treatment of crude systems are presented.

The purpose of this paper is to give a general report of water treatment as it applies to secondary oil recovery by water repressuring. It is not meant to be technical but rather informative, explaining the general considerations to be given to the treatment of water. It is also meant to assist in coordinating the efforts of the different departments involved in the planning and operation of a water treating system.

This paper presents the theory of emulsions, mechanics that usually create them and methods of emulsions, mechanics that usually create them and methods of emulsion treatment, including treating systems. The ability of iron sulfide to stabilize emulsions is also discussed, as well as a technique for iron sulphide removal from treating systems and equipment.

Knowledge of rock properties can be valuable tool in designing treatments for problem formations. All formations in the Permian Basin could be considered problem formations, but only the Delaware, San Andres, and Wolfcamp are discussed here. These rocks are of particular interest because of recent findings in core analysis and Scanning Electron Microscope (SEM) studies. The characteristics of these formations revealed by these studies have provided clues for improving treatment techniques. The new techniques are providing productivity increase many times greater than conventional treatment techniques. This paper describes the studies of the three formations, the results of the studies, and the use of these results in the design of improved treatment techniques. Field results are used to support the success of improved treatment design in providing greater production increases.

The basic practices to consider in the design, operation and maintenance of subsurface injection using a closed type system are discussed. Factors influencing the quality of water, methods of testing, and procedures to improve or maintain the quality of water desired are given.

Separation of oil and water (particularly the separation of small volumes of oil from large volumes of water) is a problem of increasing importance to the oil industry. The economics of handling large volumes of fluids often dictates the use of simple gravity-type separators for most of these separations. So long as the separators fulfill their function, there is little concern about flow characteristics, but when they fail in this function, normal oilfield practice is either to increase chemical, to add additional capacity, or to use some combination of both. It is often true, however, that the fault is due not to inadequate capacity or improper treatment, but is due rather to poor hydraulic characteristic of the separator. The only feasible method for determining the flowcharacteristics of a continuous separator is by the use of a tracer technique. The presence of such phenomena as short circuiting, the existence of stagnant flow regions, the presence of high rates of mixing and dispersion in the vessel, and other such hydrodynamic ills are easily identified by use of the tracer-response technique. Measurements can be made during the operation of the separator without interfering with it in any way, and thus measurements can be used to check the effect of variations in any of the operating parameters of the system. The causes of such hydrodynamic problems are numerous. They are rarely obvious from superficial examination of the system and, in our experience, are the rule rather than the exception. Plug flow is a very rare phenomenon in oil-field separators. Poor hydraulic characteristics of a separator can result in inadequate capacity, if a substantial fraction of the fluids spend insufficient time in the separator due to poor flow paths. Poor hydraulic characteristics may also contribute to poor treatment efficiency by introducing shear forces which decrease the droplet sizes and make separation more difficult for the same time interval. In this paper, the procedures required to make such measurements in the field are discussed, and the details of a successful method are described. Some of the results obtained in field measurements will be shown and the results discussed in terms of the hydraulic characteristics of the separators.

Although the expression only used today, many times it seems the may not be g well operations. This paper will review the features and benefits of a built-in Flux Vector Drive for Beam Pumping. The Flux Vector Technology incorporated in this controller is different from an off-the-shelf Variable Frequency Drives in that it is designed and built for Oil Field Applications and includes application specific software and firmware, which provides the operator with a unique tool that brings a new meaning to te Intelligence. This to control the speed of the pumping unit in each direction of every stroke - in order to meet a pre described pump fill target. The drive also controls rod-force, by slowing or stopping the unit when a predetermined minimum or maximum rod stress is reached. A bridle separation limiter prevents rod float by automatically adjusting the down stroke speed. The gearbox ratio calculator automatically computes the overall ratio between the motor and crankshaft throughout each pump stroke. These features, along with many others included in this Flux Vector Drive, will be reviewed in this paper and case histories will detail actual benefits to the operator.