What is "stray current" and can it cause corrosion of my downhole equipment? Stray current, both DC and AC, is
known to cause corrosion of steel in contact with the earth. Phenomena which cause such corrosion, circumstances
conducive to corrosion by stray current, and practices for preventing stray current corrosion of pipelines and well
casings are fairly well understood and accepted. Anecdotal reports of stray current causing corrosion of structures
NOT in direct contact with the earth also abound. Well tubing, sucker rods and downhole pumps are among the
most interesting of these types of equipment where stray current is sometimes proposed as the cause of observed
corrosion. This presentation will discuss stray current corrosion of downhole equipment in light of experience and
theories which have been accepted for "classical" stray current corrosion of pipelines and well casings.

Many dually completed oil wells are flowing and may be expected to continue flowing for many years. The flowing life of other dual oil wells is relatively short for one or both pays. Some dual oil wells never flow and require artificial lifting equipment at the time of completion. Pumping equipment that would lift well fluids separately and simultaneously from dual wells was developed in 1947.
This pumping equipment was developed with two purposes in mind. First, it was designed to provide a means by which the operators of dually completed oil wells can pump one or both producing formations without co-mingling fluids. Second, it is designed to provide a means by which the operators of singly completed oil wells can recomplete their wells as dual producers. Great economic advantage can be obtained in many fields by producing two pay simultaneously through one well bore. The practical possibility of pumping two producing formations simultaneously offers substantial investment and operating savings compared with twinning wells, or producing a lower pay to depletion.

This paper presents a procedure for calculation of electrical submergible pumping installations in oil-producing wells. The calculations take into account the existence of vertical multiphase flow in the production string. Special attention is given to the determination of the proper pump setting depth, and to the pressure head which must supply to the well fluids. The consideration is made that the amount of entrained free gas, which goes through the pump, must be such that it does not noticeably alter the pump performance curves. The procedure was programmed for an electronic computer. A numerical example, indicating the way in which the results can be utilized to select the equipment used in the installation, is included.

To protect the investment in a submersible pump all facilities available must be used to insure against premature unit failure. A combination of common oilfield test procedures, including the recording of fluid volumes, pressures, unit voltages, and amperages can provide the desired insurance. A correctly designed submersible pump will provide a relatively maintenance-free, long duration operation. The usual cause of premature failure of a properly designed unit is an unattended correctable mechanical malfunction which results in downhole failure. It is, therefore, mandatory that each unit be properly and rigorously monitored in order that these malfunctions be corrected before premature failure occurs. One of the most valuable and least understood tools available is the recording ammeter. The ammeter chart, much like a physician's electrocardiogram, is a recording of the "heart beat" of the submersible electrical motor. Proper, timely and rigorous analysis of amp charts can provide valuable information for the detection and correction of minor operational problems before they become costly major ones. This paper deals with the proper interpretation of ammeter charts and their interrelationship with other guides in the troubleshooting and preventive maintenance of electrical submersible pumps.

Submersible pumping applications are becoming more and more commonplace in the oilfields. Many oilfield personnel are quite familiar with the beam pump and its characteristics. Just as this unit has served reliably over the years, a properly installed and controlled submersible should give a respectable service life and should pay for its existence many times over. Maximizing the service life of submersible equipment entails the proper utilization and understanding of submersible motor controls. A variety of motor controls and their many features, ranging from simple load-break magnetic circuits to the more sophisticated solid-state monitoring technology, will be presented. This paper will treat not only control junctions but also what benefits the user can realize by proper application and analysis of particular control areas.

The design and construction for subsurface disposal of industrial waste water is presented in this paper, based on the results of El Paso Products Company Mize No. 1 Disposal Well, Ector County, Texas. The data presented encompasses the drilling, completing, and operating of a disposal system for the Odessa Petro-chemical Complex.

The subsurface electrical pump, being a relatively high-volume type of artificial lift, is most applicable in wells which are under the influence of a strong water-drive or waterflood and have high water cuts or low GOR"s. The economics of producing these high water-cut wells is directly related to the cost of electrical energy used and the operating lift of the equipment. To optimize the electrical cost and operating life, one must understand the basic characteristics of the motor, centrifugal pump and cable. This paper covers those basic concepts and presents a well test analysis technique with the corrective steps to be taken to accomplish the lowest cost per barrel of fluid lifted.

Tiltmeter technology, as a source of data acquisition for fracture mapping, has been largely neglected. The benefits of this technology, however, warrant a closer look at its capabilities. This paper serves to re-introduce tiltmeters, illustrate how they work, explain their value, and explore how tiltmeter technology is pushing forward.

Hydraulic pumping made its appearance as a method of oilwell artificial lift in the early 1930"s. Since that time this method has found wide acceptance, especially in deep, high volume pumping. Because the unit is located near the bottom of the well, understanding the operation and condition of the downhole unit can often be a problem for the producer. This paper presents a well-site analytical method using pressure and production data to determine useful information about the overall condition of the hydraulic pumping system along with the well's potential. Thus, by thoroughly understanding equipment and well conditions, the producer is in a better position to reach his goal of maximizing profit. The hydraulic pumping system analyzed in this paper consists of a downhole hydraulic reciprocating engine directly connected to a reciprocating pump which functions as a unit. There are many configurations of downhole units available such as tandem engines with single pumps, tandem pumps with single engines, tandem pumps with tandem engines, and a large selection of power ratios. Also, downhole tubular arrangements vary depending on application such as casing free, fixed casing, parallel and fixed insert. Since the operation is basically the same, the method discussed in this paper applies generally to all. Also of importance are the two types of power fluid arrangements, i.e. open and closed systems. The closed system keeps the power fluid separate from produced fluids as compared to the open system which mixes produced fluid and power fluid as they are discharged from the unit. Most systems are of the open type because of simplicity of design and reduced equipment costs. This paper discusses the open type only; but with minor modifications, the closed power fluid arrangement can be analyzed as well.

One of the most expensive pieces of production equipment to be placed downhole is a sucker rod pump. The performance of this pump can greatly affect the ability of a well to produce. By collecting information about a pump and its components through failures and successes, the operator can operating costs, decrease downtime, and increase production. Computers placed at the pump repair shop can capture detailed information about the configuration of a pump when it is assembled or when it is repaired, before being placed downhole. Later, as it is inspected after being pulled from the well, information about the condition of each component may be recorded. This data can be assimilated in a variety of ways to determine statistical trends and provide a foundation for an analysis of what works and what doesn"t. By coupling this information with other facets, such as chemical treatments, surface unit and control panel information, well tests, etc., a very effective program for reducing failures and lifting costs while increasing production may be implemented.

A review of the "building blocks" of subsurface pumps illustrating blunders of the past and headaches of the future in the selection of pumps. Included will be methods on how to properly select sub-surface pumps.

A common trend in our industry is to minimize gel concentrations and utilize the lowest viscosity fluid availah to place proppant. Barrett Resources Corporation has found, for lenticuiar microdarcy formations, that one of the keys for success is enhanced proppant transport, This is achieved incorporating stable gels which maintain greater than 1000 cps viscosity at bottomhole static temperature for the duration of the treatment. An extensive case study has been completed, involving over 500 fracture stimulation treatments in mom than 175 wells, that illustrates the poor results achieved in the Williams Formation of the Mesaverde Groups using low viscosity fluids. Low viscosity fluids invariable exhibit poor proppant transport. The statistical study shows that larger treatments utilizing "perfect proppant transport" fluids gain superior results. Based upon the case study, 100% economic success has been achieved upon incorporating stable fluids containing delayed breakers, reducing pad volumes to less than 50h of total job size, and minimizing echelon fractures while implementing a limited entry stimulation technique.

The Cornell Unit is a 778.2 m2 (1,923 acre) waterflood project in the Permian, San Andres, dolomite reservoir located in the Wasson Field, Yoakum County, Texas. The Unit currently consists of 66 producing wells and 26 injection wells. Production is approximately 1430.9 m3 (9,000 barrels) of oil per day, 1367.3 m3 (8,600 barrels) of water per day and 240,693.2 m3 (8,500,OOO cubic feet) of gas per day. Daily injection averages 4133.7 m3 (26,000 barrels) of water. Early in 1979, it was recognized that a substantial reconditioning and infill drilling program was needed to prepare the Unit for a tertiary recovery project. Casing of open hole injectors and selected producers began in mid-1979 followed by infill drilling in early 1980. Well stimulation by acid treatment is a routine completion procedure for these wells and, initially, the means to positively distribute the acid to the perforations was through the use of closely spaced straddle packers. Frequently, it was found that most of the perforations communicated while being acidized. Because of this communication, not only would other mechanical means of diversion within the well bore be unsatisfactory but diverting agents, which rely upon differential pressure temporarily sealing over the perforations, also would fail when the pressure across the perforation equalized. The need for a diverting agent which actually would enter the formation taking the acid and temporarily block it led to useage of a gelled and complexed guar gum material, commonly called High Friction Gel*. The success of High Friction Gel in achieving better overall distribution of the acid treatment is presented in this paper.

San Andres producers in several areas of Gaines County, Texas are limited on stimulation injection rates due to the proximity of potential water producing intervals. The San Andres is a dirty dolomite formation with a bottomhole temperature of approximately 135_F. Usage of acid to stimulate the formation is desirable, but given the low injection rate restrictions, diversion and penetration of the acid into the formation are difficult to accomplish. Prior treatments using rock salt for diversion resulted in most of the salt falling into the rat-hole. Recently, success has been achieved utilizing a viscoelastic acid diversion system and a chemically retarded acid system pumped in alternate stages. Injection rates have been held to 3 BPM or less, with pressure increases from diversion being observed. Initial production responses have been from 2 to 7 times more oil and 2 to 5 times the water.

The CO2 foam fracturing fluid provides a gas drive to assist removal of the treating (load) fluids after the proppant has been placed in the formation, establishes permeability to gas within the formation volume that has been saturated by load fluids, and minimizes the actual water volume that is required to place a given volume of proppant in the formation. Due to the high density of the liquid CO2 mixture, the CO2 foam can be utilized on deep, high pressure formations without experiencing prohibitive wellhead treating pressures. The CO2 also reacts with the water in the foam to form carbonic acid, so that the overall pH of the system is reduced (thus reducing the damaging effect of the fluids), and it lowers the surface tension of the load fluids so that they can be recovered more rapidly and efficiently. Field experience in the Ark-La-Tex area has demonstrated that the CO2 foam system can be used successfully in low permeability oil and/or gas sands and carbonates, at depths ranging from 2900' to 14,000 ', reservoir temperatures of 120_F to 370_F, and reservoir pressures of 1000 psi to 13,200 psig. Treatment histories and pressure transient tests have demonstrated that many of these formations are sensitive to some fluids utilized in conventional gelled water fracture treatments. A comparison of CO2 foam with several other stimulation methods demonstrates its overall success. In many instances the production results obtained with CO2 foam fluid are superior to more conventional systems that have been used in the past.

The subject matter of this paper will describe Binary foam fluids, their advantages and how they have been applied to increase production in various tight gas sands in Southeast New Mexico. The paper will include a discussion of the formations stimulated, production results, and typical treatments for tight gas sands. Furthermore, the paper will include comments on Binary foam design utilizing three dimensional fracture simulators and considerations for workover candidate selection.

Fracturing designs are generally based on information from 2D simulators, 3D simulators, field experience, or previous designs. Once a fracturing job is designed and a fracturing schedule is established, the job is usually pumped according to design without any changes. Because of such inefficient planning and procedures, millions of dollars are wasted each year on fracturing jobs that fail to provide the expected results. Preplanning and real-time analysis are key factors for successful hydraulic fracturing and increased hydrocarbon production. The following seven-step process can be followed to incorporate real-time analysis and improve fracturing procedures: 1. Gather information about the initial wells to be stimulated. 2. Design a fracturing procedure based on information and well parameters. 3. Perform a step-rate test and pump-in test to evaluate both the formation and near-wellbore regions. 4. Fracture the first well as it was predesigned. 5. Analyze pressure response during the fracturing procedure and perform pressure matching to obtain fracture parameters such as propped length, propped height, and conductivity. 6. Use the information collected in Step 5 to modify the original design. 7. Continue real-time analysis on each well. Implementing this seven-step process should enable producers to achieve the best possible fracture design.

Corrosion of injection equipment is a common problem in CO2 miscible injection operations. The two basic mechanisms by which this corrosion occurs are from internal corrosion caused by holidays in the injection tubing coating as well as from external corrosion caused by CO2 invading the tubingcasing annulus through minute seepages in the downhole injection equipment. Unfortunately, these problems are both common and costly. In one West Texas CO2 injection project, Unocal Corporation, using state-of-the-art connection and testing procedures has developed a method of installing downhole CO2 injection equipment which virtually eliminates this tubing-casing communication. In addition, the internal plastic coating of the tubulars remains intact and holiday-free during field handling procedures. The system involves the use of a helium connection test combined with meticulous attention to detail in the field handling and connection of the tubulars. The following is a discussion of the development and implementation of these procedures.

TEXACO U.S.A. has successfully installed an automation system which provides distributed remote control and monitoring of the entire array of producing operations at the Wharton and Robertson Waterflood Units in Gaines County, Texas. A preliminary economic analysis of the project indicates that the benefits attained have exceeded expectations. Microprocessor based Remote Terminal Units (RTU's) are used to detect and report alarm conditions and operating data to a Master Terminal Unit (MTU) located in a field office on the Wharton Unit. RTU's have been eveloped to provide the following functions: 1.) Control beam pumped wells. 2.) Monitor variable speed driven electric submersible
pumped wells. 3.) Monitor and control individual injection wells. 4.) Perform automatic well testing and monitor the operation
of the production satellites. 5.) Monitor the operations at the tank batteries. 6.) Monitor and control the water injection plants.

A liner is probably the most critical string of pipe set in a well. One of the most common problems encountered in liner cementing is the migration of gas in the annulus during the cementing operation. This can lead to a leaky liner top and a subsequent remedial squeeze job. By using proper cementing techniques and materials, including mud removal procedures, gas migration can be minimized and the need to squeeze liner tops can be reduced. Recently, several liners were set in wells in Lea County, New Mexico, in which different drilling conditions and problems were encountered (Table I). This paper presents case histories of these wells and the cementing techniques and systems used to combat these problems.

Sand, Iron Sulfide, Frac Sand, and other particulates produced with the fluid often cause sucker rod pumping problems that shorten sucker rod pump runs to unacceptable times, or actually prevent successful use of sucker rod pumping. Common sense methods of successfully dealing with these particulate problems will be covered as will developments in sucker rod pumps for successful particulate production.

When dealing with cementing operations with problematic formation issues, achieving satisfactory top of cement (TOC) is essential. A central Texas operator encountered zonal isolation challenges that resulted in inadequate TOCs. One of those challenges was achieving a density both above the pore pressure and below the fracture gradient. In some wells, this density window was as narrow as 0.02 to 0.04 psi/ft. Karsts and tectonic-fractured formations exist in this field, which often result in uncovered zones and TOCs at unacceptable levels. Formations such as these, with heavy erosion and cave-related brecciation, can have huge voids at volumes that are nearly impossible to measure. To meet regulatory requirements and achieve successful zonal isolation, competent cement sheaths are necessary. Initially, expensive cement-squeeze applications evolved as the zonal isolation effort was initiated in these trouble wells. However, it was decided to use a conformance product to allow the cement column to exist at a high enough level to be deemed a successful solution without the aid of the squeeze application. This
paper presents a case history of several central Texas wells in which satisfactory TOC was difficult to achieve. The challenge was to get cement high enough to meet regulatory requirements, without having to perform a squeeze job. The wells discussed exist in an environment with washed out formations occurring in a narrow window of design density. The design criteria involved overcoming these washed out regions that consume cement volume. The service company provided a solution of using a conformance product to achieve adequate TOC without the aid of a squeeze application. This paper compares several wells before and after using this water super-absorbent polymer procedure, demonstrating an improved percentage of adequate TOCs and significant cost savings to the operator.

Sucker rod connection failures seem to be a problem to some operators, while others do not seem to have the same problems. The connection should be the strongest link in the sucker rod string while the rod body should see more failures. There are three main classifications for the connection failures. These are: manufacturing discontinuities or defects, mechanical damage (including handling and make-up procedures), and loss of displacement (LOD). This paper will: discuss the API industry connection, discuss the three failure classification areas, and provide many
example pictures of the failure causes Additionally, recommendations will be provided on how to prevent future connection failures.

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 are not yet 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 ratio of rod couplings on HDPE lined tubing to that of bare steel tubing at various temperatures. The data was used to develop an equation to calculate the drag in HDPE lined tubing compared to that of bare steel tubing as a function of temperature. Although not quantitatively analyzed in this study, a side load capacity difference between HDPE lined and bare tubing was also observed

After consideration of all component parts in a sucker rod pumping installation, it is believed that the sucker rod string most directly affects the action and performance of the entire system. Sucker rod behavior, in transferring the forces and loads that are involved, determines the action of the subsurface pump. The load imposed on the surface equipment are attributed directly to the inherent characteristics of the sucker rods. The allowable stresses , range of loads imposed and speed of operation, which a sucker rod string can withstand without excessively frequent breakage, limit the economic depth and capacity of an installation.