Sucker rod coupling friction values are used by rod design software to calculate rod loads for bare steel tubing on steel couplings.  The friction values for sucker rod couplings on HDPE lined tubing is not known or defined. Therefore, rod load calculations in HDPE lined tubing are problematic. Tests were performed to compare the coupling friction in HDPE lined tubing compared to bare steel tubing at various temperatures and side loads. The objective was to find the drag ration of rod couplings on HDPE lined tubing to that of bare steel tubing at various termperatures.  The data was used to develop an equation to calculate the drag in HDPE lined tubing to that of bare steel tubing as a function of temperature. Although not quantitatvely analyzed in this study, a significant side load capacity difference between HDPE lined and bare tubing was also observed. 

This paper presents three years of field experience showing dramatically improved rod string performance, resulting in lower intervention costs.

There are three key factors in achieving this improved performance. First and foremost is the rigorous application of best practices for rod handling, connection cleaning, preparation and lubrication. Second is the use of a fully automated rod tong which delivers accurate CD control on every connection in the string. She third factor is a secondary measurement of true torque for each connection, giving further assurance that proper pin tension is achieved.

This experience has demonstrated that API 11BR does contain the proper recommended practices for successful rod makeup. Suggestions are presented for future topics which could be considered for further enhancement of API 11BR.

In Greater Green River Basin, Wyoming In order to keep capital cost down in tight gas fields, the slimhole 3%" wellbore was developed. Due to the large pipe diameter, high line pressure and low rock permeability, liquid loading becomes an issue early on a wells life cycle and, in most cases, liquid loading is immediate upon first delivery. 3%" plungers have proven to be an effective method for deliquification of the slim hole wellbore utilizing the larger-cross sectional area to effectively push the plunger and accumulated liquids up the wellbore. In comparison, using the Foss & Gaul Calculation, the 3%" plunger can operates with a lower differential pressure across it than smaller tubing sizes. The 3%" slimhole plunger has been successful in restoring production to the original decline curve or eliminating the hyperbolic decline recognized when liquid loading occurs. 3 %," plungers are currently pushing the existing fluid lifting limits and new 3%" plunger technologies such as freecycle plunger lift systems are under evaluation. In this paper the authors will describe the process of evaluation that was used and provide details of the operational problems that were encountered and how they were handled. They will go on to provide production data for several case study wells that illustrate the effectiveness of the plunger lift system and its close adherence to the performance predicted in the evaluation process.

This discussion deals with the packed hole assembly drilling technique to "controlled deviation drilling," how one tool can be used to help accomplish this both economically and easily, and proof of the performance of this tool.

The need to produce large volumes of fluids from secondary recovery wells, and to produce normal levels of fluid from deeper wells, made possible an innovative artificial lift option using a Dual Displacement Pump.(Fig. 1) Reciprocated with a standard beam pumping unit using coiled tubing, this production system (patent pending) consist in reciprocating a plunger of a down hole pump, were both motions of the pumping unit are utilized to convey fluid to surface. While in the down stroke production reaches surface through the annular space between CT and production tubing, in the up stroke fluids reach the surface through the annular space between CT and production tubing, The pump design incorporates two independent sets of traveling valves and two sets of standing valves with only one Plunger/barrel configuration.

This article covers the actions taken and results obtained in controlling sucker rod pin failures in the period 1963-1983 at the Cerro Dragon Area, Comodoro Rivadavia, southern Argentina.

The term "hydraulic pumping system" as used herein, is taken to mean a particular method of lifting fluid from oil reservoirs, in which a power pump, distribution lines, subsurface pumps, and other auxiliary components are employed. Some of the most familiar manufacturers of this type of pumping equipment are Kobe, Inc., Sargent Engineering Corporation, and National Supply Company. Sometimes this system is referred to as "hydraulic rodless pumping", but in the strictest sense this is untrue because there is always a rod connection the engine and pump pistons. However, sucker rods are not required in this mechanical reciprocating pump, which may have contributed to this system being termed "rodless". It is very difficult to compare one pumping method with another unless the comparison is restricted to specific applications.

It is probable that more effort has gone into a study of corrosion control in the Brown Bassett Ellenburger Field than in any other single gas field. This is as it should be, since the corrosion problems encountered are more severe than those generally encountered.

The Pressure Fluctuating Tool (PFT) utilizes a bi-stable, fluidic oscillator to create pulsating pressure for breaking down and/or cleaning up perforations in oil, gas and injection wells with or without stimulation fluids. The pressures generated by the PFT are from 1,500 psi above hydrostatic to 1,500 psi below hydrostatic at 140 to 150 cycles per second. This focused energy has been very successful in perforation tunnel clean up as will be indicated in the detailed case history review contained in this paper.

The cost of conventional methods of paraffin control in pumping wells is often high. This paper describes an experimental installation for the injection of butane on a pumping well in Carter County, Oklahoma, in 1958, and subsequent expansion of the process to eight other well. The frequency and quantity of injection varies with the prevailing surface temperature conditions, and to date only minor problems have been encountered using the butane injection process.

As with all industries, the fracturing industry has gone through many technological advances over the years, and with these come many successes. Using a low polymer energized fluid seems to provide a good solution for these types of problems. These new style treatments provide faster cleanup, better flow back, good sand placement, and better production than conventional or previous fracturing fluids. The case studies provided will show that this treatment fluid technique provides a positive response for these types of wells. Low-polymer energized fluids can provide the qualities and properties to enhance completions and improve project and well economics.

This paper is a case study of the selection procedure for the various types of artificial lift equipment utilized in the Reinecke Unit, Reinecke Field, Borden County, Texas. The considerations involved in choosing a Jet pump, Submersible pump, or Rod pump for maintaining optimum production performance in a high capacity reservoir are reviewed and evaluated.

The rapid expansion of the petroleum industry has caused a shortage of experienced field personnel. Even though there are volumes upon volumes written regarding specific stimulation techniques and processes, one finds that many of the routine aspects of performing these treatments are overlooked. We will look specifically at a study of optimized perforation costs in relation to hydraulic horsepower requirements, optimization of stimulation fluids - first in terms of unit cost, and then take a particular fluid and look at treatment cost compared to productivity increase.

Hot oil treatment of flowline and downhole paraffin problems is still common in the oilfields of North America. The use of chemical programs has been growing but often the industry is unsure which type of treatment should be done and if these programs are more cost effective than hot oiling. This paper will attempt to show, based on the paraffin problems being experienced, which type of chemical treatment would be most cost effective. Case histories of economic treating programs will be presented.

Matrix acidizing is often undertaken to improve the permeability of reservoir rock. When excessive quantities of ferric (Fe+++) ions are taken into solution by matrix acidizing, iron deposition and permeability reductions can occur after acidization. Sources of iron include (1) iron oxides from tubular goods, (2) pipe scale and (3) iron in mineralogical form such as siderite, pyrrhotite, magnetite, hematite and pyrite. Preventing iron deposition in matrix acidizing is essential to a successful acid treatment. This paper details a relatively new technique for controlling the precipitation of ferric compounds in matrix acidizing by incorporating a reducing agent/chelator blend. This new method is compared to three older techniques commonly used in iron control: buffering the pH, chelating, and a combination of buffering and chelating. Using standard wet chemical methods, the sequestering capabilities of the various iron control methods are evaluated at various values of pH and temperature. The effect of calcium ions on iron-sequestering capacity is also demonstrated in the paper.

This paper presents a discussion of fracture height measured with gamma ray and temperature surveys and fracture height predicted with a real-time model during the pumping of a fracture treatment. The San Andres formation was fracture stimulated ii; six West Texas wells. Each treatment was pumped down the annulus with open-ended tubing in the hole. The open ended tubing pressure was monitored to obtain direct measurement of bottom-hole treating pressure. Throughout each treatment a real-time quasi 3D fracture model was run to predict fracture geometry. After each treatment, gamma ray surveys were run to determine fracture height. A temperature survey was also run in three of the wells. Excellent agreement was obtained between the post stimulation survey fracture height and the quasi 3D model predicted fracture height.

Many times a certain prime mover is selected because that particular make and size is known to the purchaser. Little or no consideration is given to the various types of engines available, one of which may be best for the particular installation. To make an intelligent comparison of slow and high speed engines and be able to make a proper selection of a prime mover for a particular installation it is necessary to understand the definition, the principle of operation, the mechanical construction, and the advantages and disadvantages of each type of engine.

Rod pumping units historically used a crank driven walking beam to provide a reciprocating motion for oil and gas production. Several geometries have evolved over the years to produce desirable polished rod motion profiles and gearbox torque loads. These mechanical systems are limited in their ability to manipulate the motion profile and the profile is forever fixed by the selected geometry. Hydraulic cylinder linear actuators became available a number of years ago for reciprocating rod pumping of oil and gas wells. Electrically driven rack and pinion linear actuators have also been recently developed for rod pumping applications. These hydraulic and electric linear pumping units share some common advantages over mechanical pumping units. Linear pumping units are generally less massive than comparable walking beam units and can be mounted directly to the well head. The cost savings on site preparation, transportation logistics, and equipment installation can be substantial. Linear actuators also have an important advantage in their ability to provide programmable control of polished rod motion profile and closed loop control of polished rod load. The relatively low mass of linear actuator mechanisms allows nearly instantaneous adjustment of polished rod velocity and load. Linear pumping units provide independent control of up stroke and down stroke peak velocities as well as the shape of the velocity profile. Controlling the velocity profile allows increased pump cycle rate and associated production without exceeding rod fall velocity limits. Velocity profile control can also be used to reduce gas interference and fluid pound. Rod stroke position can be controlled to provide period pump tapping to overcome down-hole pump problems. Polished rod load control can be used limit minimum rod load, eliminate bridle separation, and damp rod load oscillation.

In lieu of pending EPA and NRC regulations covering the monitoring of ground water supplies of drinking water as it relates to the public health, both private and municipal water districts, and utilities will be required to monitor for naturally occurring radioactive materials, NORM, and their constituents, ie... Radon, Radium, and Thorium. This monitoring will require the utility districts to utilize and employ "BAT", best available technology. A more advanced set of CAE, computer aided engineering, tools are beginning to appear that combine data, graphics, and analysis capabilities within a spatial model. CAE tools are considered in this paper to fit into the BAT category. CAE can assist independent water districts as well as broad based watershed and aquifers utilized by municipal water districts in data management, engineering analysis and complex site visualization. Water companies can project regions that could create an environmental impact on public health. Data involved, ie... mechanics of ore zone hydrology in aquifers, in site assessment and analysis can now be integrated into a single model called a virtual site. The virtual site concept of data management uses an electronic version of a geotechnical engineer's conceptual site model. Please refer to Appendix A for a more detailed description. The petroleum industry is also being impacted by a multitude of environmental issues, both past and pending legislation. Many petroleum companies are initiating a proactive environmental policy. CAE functionality can assist them by providing a vehicle for complex site data management, engineering analysis and site visualization. Concurrently, NORM is under proposed regulations (Revision 3) under the Texas Department of Health Radiation Control. Using the virtual site, engineers can directly query, edit, or manipulate data while the consequences of changes made cascade through the model. To explore the many ramifications of NORM and other potential environmental hazards, 3D graphical presentations of site specific scientific visualizations can be calculated and displayed on the fly.

The variation of centrifugal pump performance curves with liquid viscosity is a well-known fact and is usually properly accounted for when selecting such pumps for oilfield service like artificial lifting by ESP units, pipeline transport, etc. Thus, several theoretical and empirical methods are available for correcting performance curves (conventionally measured with water) to other liquids. Most of them utilize specially developed charts and tedious hand calculations and are viable for simple design calculations but find very limited use when a great number of cases is present or when computerized calculations are desired. The aim of the present paper is the development of specific formulas instead of charts to be used for correcting the performance curves of centrifugal pumps for higher viscosities. The formulas are based on the widely used and generally accepted procedure of the Hydraulic Institute whose previously published charts, after digitalization, were fitted with analytical functions of the relevant parameters. The model introduced in the paper easily lends itself to computer applications and may be used as a subroutine in many kinds of program packages that involve selection or evaluation of centrifugal pumps. The use of the model is illustrated by a detailed example problem. At the end of the paper, two additional examples are shown to prove the accuracy of the proposed model. Here, calculated performance curves are compared to actually measured ones for two pumps in pipeline service. The two examples prove that the proposed analytical model gives very good accuracies.

Before we start to discuss "Optimum Pumping Conditions" let us first see what Webster's Dictionary gives as the real meaning of "optimum": "The best or most favorable degree. Best, most favorable or most conducive to a given end, especially under fixed conditions." The first and most important key to optimum pumping is the establishment of fixed conditions. As we all well know, the basic purpose of any pumping installation is to pump fluid from the well to the surface. In order to establish a set of fixed conditions around which we can establish optimum pumping, we must consider all of these factors which are most important and then we must decide to what degree they really are fixed or stable.

A comparison was made between four commercially available sucker rod string design programs: Rod Star, S-Rod, Q-Rod, LoadCal B and a proprietary, modified API RP11L based program. These programs used the same input requirements, where applicable, and their outputs compared dynamometers cards from five different producing wells. The results show differences in the anticipated major design loads along with differences in the output information. Recommendations are made on potential changes to these programs and comments are made on things to consider when these programs are used.

A geographical and lithological diagram pertaining to oil well cementing is presented for the Delaware Basin of West Texas and New Mexico. The composite cementing programs were selected from jobs performed in the area. Jobs selected were used as examples of design considerations for the problems which can be expected in the area. The materials and equipment are discussed in relationship to formation conditions which determine their selection. Cementing techniques of the area are presented in detail. One method considered unique to the area is presented. Particular attention is given to the difficult combination of lost circulation formations having low break-down pressure associated with relatively high pressure formations. The considerations of high temperature cementing are discussed in relationship to the deeper formations. This presentation considers the basic chemical and physical properties of cementing materials and their use to satisfy the design considerations necessary to successful cementing operations in the Delaware Basin.

Fluid pound has long been a problem with maintaining good run life of the pumping system. The result of fluid pounding is costly and deprives the industry of dollars that can be used to invest in improvements instead of repairs. With the bottom line decreasing, how can each operator remain in business and stay profitable? The cost of making that extra barrel of oil may be greater than the revenue received.

A discussion of the Cummin CD&W San Andres waterflood project in Ector County, Texas is presented. This waterflood, operated by Cities Service Oil Company, began in 1961 with a pilot consisting of four water injection wells and one oil well. The project has been expanded to twenty-eight injection wells and twenty-five oil wells based on the results of the pilot project. Secondary oil recovery to date exceeds 800,000 barrels. The success of the project has been attributed to close spacing of water injection wells and relatively low water injection rates.