Failures in the sucker rod industry can be costly and time consuming. A thorough understanding of the critical factors affecting the overall reliability of steel is important to address these failures. Sucker rod manufacturing involves a lot of processes from different industries. The manufacturing and servicing of steel sucker rods involves a chain of processes starting with the steel mills, sucker rod manufacturer and eventually goes to the end user. There are a lot of critical factors involved in every step of the process before the product goes down hole. The goal of this paper is to prevent failures through awareness and education of critical factors affecting the overall reliability of
steel products used in oil production. The topics addressed in this paper are as follows: 1. Methods of steel rolling (traditional ingots vs. modern continuous casting). 2. Induction heating & upsetting and factors affecting the final quality of the steel. 3. Heat Treatment and factors affecting quality and reliability of steel. 4. Shot peening vs. shot blasting. 5. CNC machining. 6. Factors affecting overall reliability in the field.

Multiple zone WAG injection techniques have changed little over the years, relying on side-pocket mandrel / injection valve technology to accomplish injection fluid diversion to target zones. These systems rely on mechanical injection valves to disperse the injected fluid. A new technique has been put into use that both simplifies the process and provides increased reliability by eliminating mechanically operated injection valves. Side-pocket mandrel injection control assemblies have been replaced with new reservoir access mandrel systems. This paper will explore the application of this improved downhole technology for WAG injection control.

Carbonate formations are predominate in the Permian Basin and as such are commonly stimulated with acids. Success of an acid treatment is dependent on knowledge of the reservoir, design techniques and execution; and emphasis on obtaining good zone coverage. In addition, effectiveness is very dependent on how many times a well has been acidized and with what kind of acid. Case histories of acid stimulation, with production results, are presented on a new technique for stimulating the San Andres dolomite. Treatments were all low rate matrix treatments designed to minimize the increase in water production. Discussed are conditions to overcome in order to get effective acid penetration and thus stimulation. The case histories presented are on San Andres wells that have been acidized several times in the past, but where this new technique has provided an improved response over a longer period of time following the treatment.

Fracture acidizing of carbonates has yielded increases in production in many areas. But depending upon the rock strength and the reservoir closure pressure this may be lower than expected. Also, as a result of closure and rock strength, production may decline at a higher rate than after a proppant fracture treatment. Laboratory results are presented describing the effect on the strength (Softening) of a dolomite and limestone after exposure to various acid systems. A dolomite saturated with potassium chloride water exposed to neat, emulsified, gelled and crosslinked 15wt% hydrochloric exhibited strength improvements going from neat to one of the fluid loss controlled systems by approximately 70%. A limestone tested similarly showed approximately 100% strength improvement. Tests were also performed on the rocks in a dry state and saturated with synthetic oil. These tests also had marked improvements in from 25 to over 100%. Treatments using an increased volume of acid systems with lower matrix leak-off should provide longer-term production responses.

A great many carbonates are stimulated successfully utilizing acid fracturing techniques. There are several models in the industry, which will give relative comparisons of fluid performances under varying reservoir conditions. These are only good as design tools when validated. However, a great deal of laboratory time is spent testing rocks and fluids for reactivity, diffusivity and leak-off to provide the values for these models. It is on most occasions difficult to comprehend the significance of these results.Presented are the variances in laboratory generated values and their effect on the output of one of the fracture acidizing models. Several reasons are addressed as to why these variances occur. These include the difficulty in measuring accurately the surface area of samples tested, the limited amount of reservoir rock to test with all the same properties and the limited amount of time to perform the tests.

A stimulation treatment of water input wells in the massive San Andres limestone has shown the benefits that can be expected with the inclusion of nitrogen in the treatment followed by the use of nitrogen for displacement to the formation and the subsequent backflow. The San Andres is interspersed with water zones and the multiphase system helps prevent the fracturing of the formation due to gas compressibility and carefully controlled injection rates. The inclusion of a gas phase in stimulation treatments has been practiced for many years in production wells, but it has been only recently accepted in the treatment of water input wells in the Southwest. Wells treated cover the six-county area of Hockley, Terry, Cochran, Yoakum, Gaines and Scurry Counties. Two treatment techniques developed have shown that with a properly engineered treatment an increase of water input and effective cleanout of solids can be expected.

A significant quantity of gas reserves exists in deep, hot reservoirs such as the Ellenburger in West Texas.

Coreflow studies, X-ray diffraction, and a variety of other investigative techniques have been used in the study of the design for stimulation fluids for a number of years. Recently, the concern for the design of non-damaging stimulation fluids to treat "problem", well-consolidated, low-permeability low-porosity sandstone reservoirs has heightened. A typical example of a problem sandstone in the Pennsylvanian age group is the overall Morrow sand. The Morrow is considered to be in southeastern New Mexico, the Texas Panhandle, the Oklahoma Panhandle, and west-central Oklahoma at varying depths. The heterogeneity of the Morrow is displayed by the inclusion of laboratory investigation data which are necessary to point out the reasoning for the fluid types recommended in the Morrow in the abovementioned areas. Following presentation of the investigative data, various case histories will be presented to substantiate the successful use of the recommended fluid systems in what has been labeled by operators, problem areas. The significance of fluid pH, low surface/ inter-facial tension, iron chelation, and low-residue gelling materials, has been the premise for the treatment type which is being recommended for Morrow sections in the majority of the areas documented. Core data point to a general need to encounter or avoid specific components in the matrices of the Morrow sands. Core studies have shown that a recently developed combination of a weak HC 1, weak HF acid system (3%HC 1 plus 1.2 HF) and a highly effective fluorocarbon surfactant provided significant improvement in the ability of a fluid to successfully act on the inherent problems within the matrices of most Morrow sands. This implies that the Morrow is a candidate for damage, regardless of the considerations made to complete and/ or stimulate it with "so-called" non-damaging fluids such as "clean" gels or condensate. The inherent potential for damage initiated by stimulation lay in the strategic location of migrating fines, iron compounds and extraneous clays within actual permeability and porosity. To avoid particulate matter damage with even minor penetration from commercially available fluid-loss additives for either oil or water frac systems, the amount used should be carefully considered. The core studies which were run in the Morrow sections listed in Table 1 were intended to indicate the design which was most compatible and successful from the standpoint of encountering matrix conditions, and not to determine volumes to be utilized in treatment. The engineering aspects of these designs for the field followed contemporary computer methods. The flow tests were run with constant volumes for relative comparison purposes to show that significant pore volume concentrations could provide correlating data with actual recommendations followed by treatment." The scanning electron microscope has been useful in identifying the location of potentially damaging particles within the permeability and porosity of the Morrow which have been documented by X-ray diffraction.

Stimulation results from acid treatments of carbonate reservoirs are generally Limited by the extent of live acid penetration, which is determined by the rate of acid spending and fluid-loss. In recently ears, the effort to control acid leakoff and reduce the rate of spending has caused the industry to focus on developing gelled acid systems. Numerous gelling agents have been used, including natural gum, biopolymers, synthetic polymers and surfactants. Many of these materials have been used with only limit & success, due to their inherent instability in live or spent acid, or incompatibility with common additives and contaminants. In 1983, a polymer was introduced, which provides the desired characteristics of stable viscosity, acid retardation and compatibility with most of the common acid additives. It has since been successfully applied in more than 300 matrix and fracture acidizing treatments. This paper provides a description of this gelling agent and details of several case histories.

The object of this paper is to discuss the most widely used stimulation techniques currently being employed in the Austin Chalk Formation in South Texas. Although this trend has been explored for years and continues to be one of the most active in the country, there remains a difference of opinion over how to effectively stimulate this reservoir. Several schools of thought regarding types of fluids, additives, and general treating techniques will be examined. The fracture geometry of various treatments as predicted by pre-treatment computer designs will be compared to the parameters obtained from post-frac analysis.

Crude oil volume may be lost from a storage tank in the form of vapor and/or gas known as vaporization. This loss of well bore volume, which is not recoverable, is normally expelled to atmosphere. The prime question to the producer of crude oil, is what are the economics of recovering the stock tank vapor? The principles of fluid vaporization are based upon the fundamental laws of physics and will not be fully discussed at this time. Volatile liquids placed in a closed vessel, such as a stock tank, will vaporize throughout the space above the liquid until equilibrium of vapor pressure is attained. This rate of vaporization is affected by a number of operating conditions and by the type of fluid. Generally, the fundamental factor affecting the volume of vapor loss for a given fluid gravity is the ambient temperature, which is variable, and is appreciable in more areas.

With a significant oil-price drop drilling programs are stopped and marginal wells are abandoned. Production must be continued with minimum down-time if an oil company is to stay profitable. One low-cost way to do this is to stop lightning damage.
Tank battery protection is the highest priority. Fiber glass tanks and explosive gases have made this a major challenge. Lightning collection has never been truly successful. Charge transfer systems (CTS) have prevented lightning strikes with nearly 100% elimination of damage. The particulars of CTS are discussed. Electrical equipment must be protected from transient voltage surges carried in on the power wires. A listing from most important to least would be disposal facilities, electric submersible pumps (ESPs), ESP variable speed drives and pumping units. Transient voltage surge suppressor (TVSS) design and proper grounding are critically important if equipment is to be saved from lightning damage.

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.