This paper discusses several studies undertaken by Mobil's Bakersfield, California, operating unit to better understand the operating limits of oilfield pumping unit gear reducers. Theoretic information was secured from several manufactures, both domestic and foreign, about gear reducer, gear and bearing life expectations. Limited testing was conducted in an effort to validate four manufactures' claims. Inspections were also conducted on about 200 pumping units to gain a wider information base on gear reducer operating life. From these data it was determined that some manufacturers' information could be proven while others could not. A compilation of the theoretical information was developed and reports were distributed that provide Mobil with the ability to more accurately determine the maximum allowable operating limits for several brands of pumping units.

For years questions concerning problem wells have been answered thru well analysis. Current RPC technology can predict well problems, manage pumping wells, and control cycle times via the downhole pump card. This leap in technology goes beyond normal pump-off control to total well management. Guesses can be made viewing the surface card. Decisions are made viewing the pump card. Utilizing diagnostic software within the control providing the operator both the surface card and downhole pump card is like having a dynamometer and analyst on the well 24 hours a day. This downhole card detecting pump fillage will assist the operator in detecting problems in the well in advance of equipment failure, aid in diagnosing downhole conditions while maximizing production. Why control a well with peak and minimum load violations when you can MANAGE the entire beam pumping system from electric motor to downhole pump. In addition, enhanced historical data and analysis capability are available. This paper will review the anomalies of the surface card with answers provided by the downhole pump card. Actual well analysis comparisons, computer predictive comparisons, and data from Pump-off controls currently using pump card technology will be used in making operating decisions.

The negative effects of microbial activity in oil production are well-known to the petroleum engineer. Formation plugging problems or corrosion problems, especially in waterfloods, are undesirable characteristics of microbial metabolism which have been the subject of considerable expense to the industry. On the other hand, microbial activity has potential for enhanced oil recovery. The use of microbial agents to improve oil recovery is not a new idea. It has long been noted that certain microbes are capable of attacking complex hydrocarbons and producing less complex molecules.6-x Bacterial strains have been shown to produce light hydrocarbons from crude while others can produce carbon dioxide as a part of their metabolic activity. More recent developments have shown that biopolymers capable of being used as viscosifiers may be produced by a fermentation process.

This paper discusses the application of biological mixtures for prevention of paraffin deposits in oil wells. Three biological mixtures were field tested. Statistical data on test results in Canada and the United States are presented outlining application parameters. Several case histories are presented including some Thermal Chromatography-Mass Spectrometry (TC-MS) work on treated wells. Theoretical mechanisms of the paraffin control process are discussed.

Bioremediation is a new technology for which the time has arrived. This paper presents an overview of various products and processes to reclaim sodium-damaged and hydrocarbon-contaminated soils, to manage tank bottoms, and to biologically clean up sludge pits. The processes include the pre-evaluation analysis, the treatment and the follow-up procedures. Bioremediation is a costeffective way to handle the aforementioned problems in an environmentally sound manner.

Attention is being focused on more and better advance planning in drilling operations to minimize the rise in drilling costs. This paper describes one procedure for evaluating and improving drilling performance. In our study, penetration rate is not considered the sole basis for drilling efficiency but attention is focused on the more important aspect of incremental cost per foot of hole drilled.

As America's energy demands increase, major new responsibilities are placed on the industry to find new reserves. Hundreds of thousands of dollars, sometimes even millions, are spent on a single well. These high costs, coupled with limited equipment sources, make it critical that we use drilling equipment, especially rock bits, efficiently. Several years ago the cost and importance of the rotary rock bit were considered relatively insignificant to the overall cost of drilling an oil well. However, with the development of tungsten carbide inserts and sophisticated lubrication and bearing designs the rock bit has become expensive. Even though these bits can now drill through thousands of feet of rock, selection of each bit has become a very important factor in the cost of drilling operations. The proliferation of bearing designs and cutting structures since 1967 caused the International Association of Drilling Contractors (IADC) to adopt in 1973 a standard coding for rotary rock bits. This coding is summarized in Fig. 1. the new classification system was initiated to help eliminate some of the confusion among contractors and operating company personnel arising from different coding systems of the various manufacturers. The IADC selected a three-digit numerical system which classifies: 1. Cutting structure (milled tooth or insert) 2. Formation hardness, and 3. Design features. The first digit relates to the cutting structure of the bit. Series 1,2 and 3 in this position describe milled tooth bits for soft, medium, and hard formations, respectively. Series 5,6,7, and 8 describe insert bits for soft, medium, hard, and extremely hard formations respectively. The second digit is a formation hardness subclassification with numbers 1 through 4 designating formation hardness. The final digit, the bit feature classification, indicates mechanical or design features such as gauge inserts, sealed or frictiontype bearings. The IADC classification of l-l-4, for example, refers to a milled tooth bit (1) used to drill the softest formation (1) and having a standard mechanical feature of the sealed bearing (4). The IADC classification of 7-4-7 indicates an insert bit (7) designed to drill hard formation (4), and having friction bearing and gauge inserts (7).

The popular image of surface coal mining is changing. Highly trained and well-compensated mining technicians operate modern equipment in pleasant surroundings to extract low-sulfur coal from the ground. Scientific methods are used to reclaim the mined-out land, and even the needs of the native pronghorn antelope are not overlooked. The purpose of this paper is to describe Atlantic Richfield's first surface coal mine Black Thunder and some of the features that we feel make it unique.

The use of plunger lift to deliquify gas wells is an important artificial lift method to maintain and increase production. The efficacy of a plunger installation is based on several factors: the ability to confirm loading and the applicability to an individual well; the choice of the proper equipment for the most effective operation; and the maintenance of the system for optimum performance. This paper deals with (1) various methods to identify the aspects of loading, for example, by the observation of critical velocity and the use of fluid gradients, (2) the correct choice of plungers and control equipment, and (3) the proper maintenance of the equipment (plungers, wellbore, etc.) to effect proper operation.

In the Permian Basin, failure of the borehole wall while drilling vertically (wellbore instability) is seldom a problem. In horizontal wells, however, this is not the case. The imbalance between vertical and horizontal earth stresses, and the fluid pressure in the rock, can lead to problems if insufficient mud weight is used. This can lead to tight-hole and stuck-pipe problems that can escalate into losing the wellbore (and, sometimes, the BHA), requiring a sidetrack.

In this presentation the causes of wellbore instability are reviewed and the methodology for predicting a safe mud weight is described. In contrast to vertical wells, mud weight requirements in horizontal wells are more exacting. An approach to update required mud weight while drilling and geosteering will be described. Case history examples of applying this approach to wells drilled in the Permian Basin will be presented which integrate borehole stability with hole cleaning and geosteering requirements.

The paper will discuss and analyze BHP data that was recorded during actual horizontal fracturing work. The data will demonstrate isolation from one fracture point to the next. The paper will also discuss production results from 11 horizontal wells that were completed using an innovative open hole horizontal completion technique. In addition, the paper will compare production results from these horizontal wells to others in the same field that were completed using different techniques. This paper is a follow-up to the paper SPSC entitled "Innovative Stimulation Technique helps Pin-Point Fractures in Open Hole Horizontal San Andres Wells".

Bottom hole pressures have been measured for many years in the oil industry, primarily for use in productivity and future production predictions. More recently, it has become apparent to petroleum engineers that the pressure transients measured during build-up or draw-down tests contain much quantitative information about the well and the reservoir. Each year more techniques for analysis of these pressure transients become available in the literature, giving the petroleum engineer more opportunities to make money for his company through application of these techniques. This paper presents briefly the theory of some of these techniques and will explain their use by means of field examples.

In-fill development within mature producing fields has been increasing throughout the Permian Basin, West Texas. Stimulation of new wells and recompletion of present producers and injectors many times accompanies this in-fill development. Most recent studies have focused on the overall strategy of in-fill development from a petrophysical characterization standpoint. The impact of hydraulic fracturing within a secondary recovery project has not been as thoroughly investigated as to benefits in production enhancement and overall field development. Before the effectiveness of hydraulic fracturing in the secondary recovery processes can be fully evaluated, the processes involved in effectively designing hydraulic fractures in this environment need to be addressed. Hydraulic fracturing is complicated by the lack of historical data. Treatments in these fields have often been "cook-booked" and given less attention due to their smaller size and scope. Many times the process is further complicated by the interactive nature required in effective treatment modeling (i.e. historical review, candidate selection, pre-job design, pre-job diagnostics, on-site or post-job modeling, and post-job diagnostics). In this paper, we will outline the steps required to improve the process without expending excessive resources, and we will discuss the steps where streamlining the process is warranted without compromising the end result. Finally, we will document several cases illustrating effective use of these technologies to obtain more effective stress profiles and more efficient fracture treatments.

Several studies have appeared in the literature concerning details of dynamic models of beam pump and rod string performance. Many of these studies deal with the equations and models presented by S. G. Gibbs.*-" Also, some other work has indicated techniques of modeling and solutions to governing equations. An equation is developed here which is used to generate a "diagnostic" and a "design" type of beam pump analysis program. The equations needed at the interface of rods of different properties are presented and discussed. This method allows an explicit statement of the equal force boundary condition at the interface of rods of different properties. No averaging of properties is required across the interface. Also, any change in the speed of sound from one rod to another is accounted for.

Fluid viscosity reduction is commonly used to gauge polymer degradation. Although viscosity reduction indicates polymer degradation, it is misleading to conclude that this reduced viscosity equates to improved fracture conductivity. Polymer fragments which are desolubilized from the gelled fluid no longer contribute to fluid viscosity but do, unfortunately, contribute significantly to proppant pack damage. Several new breaker technologies have been introduced in efforts to improve polymer degradation, and thereby, improve fracture conductivity and ultimately, well productivity. Many production case histories have been offered as evidence of the utility of the new technologies to improve well productivity. However, the facility to quantitatively determine the polymer degrading efficiency of the breakers has heretofore been lacking. Laboratory procedures, both wet chemical and instrumental, have recently been developed to address characterization of the relative degrading efficiency of the various breakers. The analysis of the combined data provide a quantitative profile of the polymer fragments. Extensive studies were conducted employing the new procedures to compare the degrading efficiency of various oxidative and enzymatic breakers. Detailed analysis of the results are provided.

Shell Exploration & Production Company is currently utilizing capillary injection systems to deliver corrosion inhibition chemicals in several gas wells in their South Texas fields. Traditional methods to handle corrosive production wellbores has been to treat? Corrosion Resistant Alloys (CRA"s) or periodic batch treatments with corrosion inhibition chemicals. The installation of CRA materials has been the preferred method especially in the more corrosive environments, but the high cost of these materials can be prohibitive in some installations. Periodic batch treatments have also been widely utilized to protect wells where less corrosive conditions are expected. The current preferred method to protect wellbore tubulars is to install traditional carbon steel tubulars and install a capillary injection system to continuously deliver corrosion inhibition chemicals. Upon completion of a newly drilled well, a capillary injection string is installed and continuous corrosion inhibition chemical injection begun. Corrosion rates are monitored in the new installation and chemical injection volumes are adjusted to keep corrosions rates under control.

The transport of propping agent particles through the perforations, down the perforation tunnels, and into the fracture via the crosscut channels connecting the perforating tunnels and the fracture present special flow problems during hydraulic fracturing operations. Hydraulic fracturing treatments are commonly performed in the field, yet surprisingly little experimental or analytical work is available to guide engineers in selecting operating conditions to ensure that propping agent particles are transported efficiently from the casing into the fracture. This paper describes how propping agent particles are transported from the casing into the fracture. Presented in the paper is a procedure for predicting proppant agent transport from the casing into the fracture, and how the technique can be utilized to more effectively employ the hydraulic fracturing process.

The transport of propping agent particles through the perforations, down the perforation tunnels, and into the fracture via the crosscut channels connecting the perforating tunnels and the fracture present special flow problems during hydraulic fracturing operations. Hydraulic fracturing treatments are commonly performed in the field, yet surprisingly little experimental or analytical work is available to guide engineers in selecting operating conditions to ensure that propping agent particles are transported efficiently from the casing into the fracture. This paper describes how propping agent particles are transported from the casing into the fracture. Presented in the paper is a procedure for predicting proppant agent transport from the casing into the fracture, and how the technique can be utilized to more effectively employ the hydraulic fracturing process.

The brine external polymulsion acid fracturing technique has been successfully utilized by Exxon to stimulate the low permeability carbonate reservoirs of the Permian Basin. Compared to the traditional proppant fracturing methods, this approach offers the advantages of lower cost, reduced mechanical risk, and greater adaptability to difficult well situations. Polymulsion is an external aqueous-phase oil-water emulsion. The non-Newtonian properties of this emulsion create an efficient fracturing fluid which exhibits excellent pumping characteristics. The brine external polymulsion acid fracturing technique involves pumping a pad of polymulsion fluid followed by an approximately equal volume of high viscosity acid containing a fluid loss control additive. Results obtained from the application of this technique in the Drinkard formation of the B-D-T field in Eastern New Mexico and in the Clearfork- Glorieta formations of the Robertson Clearfork Unit in West Texas will be presented.

A new technology is available that provides a more accurate and dependable method of opening a valve to relieve pressure, closing a valve to isolate pressure, or switching a valve to divert pressure. An expendable pin (the buckling pin) obeying Euler's Law acts both as a sensor and valve actuator to open, close, or divert valves at an exact set pressure.

The Bull Dog@ Bailer (Patent No. 4,493,383) offers a method to clean out sand and debris from the wellbore or casing without loading the hole and circulating. The bailer tool assembly consists of a bottom hole tool, float valve, cavity as per weight chart, and the Bull Dog@ Bailer. The tool must be run in fluid, so cavity length cannot exceed the column. Reciprocation (5 ft. stroke) of the pump assembly draws fluid and sand in through the bottom hole tool, through the float valve, and up into the cavity tubing chamber. Sand and debris collect in the tubing chamber above the float valve while the fluid goes through the pump assembly and is discharged to the annulus. The pump rod is hexagonal to permit normal rotation of the entire tubing string. The size and weight of the tubing used between the float valve and the pump assembly to form the chamber may be varied to apply to existing hole conditions and desired operations. All principal parts of the tool are manufactured from high-strength, heat-treated alloy steel.

The oil industry typically selects perforators based on published performance specifications. Depth 01

Early applications for butterfly valves were restricted to throttling control in many types of fluid flow systems. These early throttling-type butterfly valves were very similar to the disc in an automobile carburetor and did not provide positive shutoff. In the early part of this century, however, semipositive low-pressure shutoff butterfly valves were developed, using natural rubber for seating materials. These valves received only limited acceptance because of natural rubber's limited resistance to media and its undesirable characteristic of deteriorating physical properties when exposed to temperature over a period of time. This water-works type valve was unsuitable for petroleum services due to the use of natural rubber seats. However, the development of these semipositive low-pressure valves coupled with the emergence of many synthetic rubbers during World War II led to the leak-free high-pressure butterfly valves we know today. The new elastomers also allowed the valve designer to obtain improved resistance to media, while providing positive shutoff. The primary function of a butterfly valve today is to achieve positive shutoff. They can be fully opened and closed in a quarter turn. Their ease of operation permits them to be used for throttling and on-off automatic applications in various fluid flow systems. Butterflies will handle many different types of media, including vapor (steam), gases, liquid, slurry and solids. Butterfly valves provide positive shutoff up to 250 psi and have far greater life than the early natural rubber-seated valves. A variety of unique design advantages are offered in butterfly valves, including weight, economy, simplicity of design, ease of installation and maintenance, compactness, simple quick operation, reliability, and versatility. The light weight of butterflies allows installation without the necessity of a hoist up to the 10-in. or 12-in. sizes. Weight economy is also a cost advantage because a minimum amount of materials are used in manufacturing and the valve design is simple, providing economical prices. A minimum amount of premium material is required in handling corrosive media since many butterfly valve designs prohibit the medium from reaching the valve body. This, of course, is not true in gate, ball, plug, or globe valves since they must have high alloy bodies as well as high alloy trims (such as titanium, hastelloy, stainless steel) if they are to be compatible with highly corrosive flow streams. In addition to economy, the simplicity of design of the butterfly allows on-site repair without special tools or equipment. Elastomers can be replaced right at the job site. Compactness of the butterfly valves, particularly the wafer design, minimizes the amount of wasted space necessary for piping systems. Little or no maintenance is required on butterfly valves. If properly selected, butterflies will provide leak-free service with a minimum of maintenance. Most butterfly valves are permanently lubricated and require no special attention once installed. Due to the many trims available in butterfly valves they are one of the most versatile valve types available today. Depending upon the proper selection of metals and elastomers, butterflies are capable of operating from -65" to +450_F and can handle media from low vacuum pressures up to 251 and including 250 psig working pressures. Among the limitations of butterfly valves is temperature. The range previously mentioned for butterflies is determined by the elastomer seals. Resilient or rubber-lined butterflies are generally available from moderate vacuum up to and including 250 psig with valves containing a limited elastomer in their seals capable of handling up to 720 psig in special designs. Butterfly valves should be closed slowly to prevent "water hammer". When butterfly valves are closed too rapidly, hydraulic shock will occur. When a valve disc is closed quickly the disc must absorb the energy that is stored in the movement of liquid it is suddenly stopping. This hydraulic shock can be avoided by the use of a gear operator or other device on top of the valve which prevents quick closing. A major criterion for maximum valve life is selection of the proper valve. Various media, valve use, cycle rate, temperatures and pressures affect the proper selection of valve style and trim. Prior to installation, valves should be carefully handled to prevent disc edge damage. Valve flanges should be welded to pipe prior to inserting the valve body. Piping must be properly supported and flanges accurately aligned to prevent unnecessary loads on valve bodies. Valve assemblies, pipeline and mating flanges should be cleaned prior to valve installation. These basic steps before installation combined with periodic checks and cycling during operation will prolong the life of any valve. Butterfly valves have emerged as a strong competitor to other types of valves in a variety of applications. Specific petroleum industry applications are listed later, but generally butterfly valves are found in all areas of the petroleum industry.

Whenever large volumes of oil-well fluid have to be lifted, the submersible pump-motor system is the most logical artificial lift system to use. The submersible pump will operate efficiently above 300 barrels per day. The submersible pumping system is composed of the motor, seal, pump, and other hardware, as well as a long length of power cable. The most obvious unique feature of a submersible system is its geometry to fit a narrow hole and its reliability to last under adverse environmental conditions without convenient access for repair or inspection. Generally speaking, cables are neither the most complex element in a submersible pumping system nor the most delicate or susceptible to damage. The majority of cables in application today last many years with a minimum of repair requirement. Nevertheless when cable damage occurs, it becomes a significant problem. Anytime cable damage occurs, the whole system has to be shut down, pump and motor pulled, and a very simple repair done, with again a feeling of having to go through all that trouble and cost for a seemingly insignificant reason. Because of this feature of the application, the process of selection of the submersible power cable needs to be understood. Historically, cables were initially made by manufacturers of general purpose cables for mining, communication, heavy machinery, and building industries. The manufacture of cables has been divorced from the oil-field production equipment industry and out of touch with the oil-field requirements. There has been little guidance, specialized technical know-how, or business incentive for the cable manufacturers to carry on intensive research and development on cable improvements for oil-well application. Submersible equipment manufacturers began to test and specify oil-resistant power cable construction in the late 1950"s. In the 1960's the manufacturers of Centrilift submersible oil well pump equipment contracted their corporate research center to undertake longterm development of submersible power cables more specifically suited to oil-well applications. Through their initiative and that of the centralized research team at Borg-Warner in cooperation with key material suppliers as well as cable manufacturers, and with field testing by most major oil companies, new cables are being developed and an extensive amount of knowledge is being generated about cable requirements, material performance, field handling practices, splicing, etc. The purpose of this paper is to provide those using or considering the use of submersible pumping systems information about the selection of cable and thus, in an objective manner, to enhance the reliability of submersible-pump systems and encourage their application.

ESP cable is an integral part of the submersible pumping system. Operating cost considerations have moved the industry towards re-use of equipment. Testing of submersible pumps, motors, seal sections and gas separators is currently being conducted by all major manufacturers of ESP equipment. A normal progression would require that ESP Cables follow the same suit. Many users currently rely on a 1000 Volt megohmmeter or a DC Hi-Pot test to determine if a cable is suitable for re-use. These instruments if used at a single voltage point may not give a true picture of the cable insulation reliability. This paper describes environmental aspects which must be considered along with a jointly developed testing procedure for determining the re-use of ESP cable. The ultimate goal of the testing procedure is to gather data and optimize the life of ESP cables under specific applications. The procedure was jointly developed by Mobil and ESP Inc. Use of the procedure was initiated at Salt Creek field in January 1992, and to date over 167 cable strings have been tested.