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.

A significant available resource of unrecovered mobile oil resides within Grayburg reservoirs as a result of low ultimate recoveries of less than 30 percent of the large estimated volume of original oil in place. This low ultimate recovery from conventional primary and secondary recovery methods is due mainly to the heterogeneity typical of these reservoirs. Evidence of this heterogeneity is well displayed in the Dune field by significant production inequalities, particularly within the Mobil University Unit 15/16. The cumulative production from Section 15 is about 10 million barrels, whereas that from Section 16 is only 2 million barrels. This difference between the two adjacent sections cannot be attributed solely to varying production practices, but rather to major changes in rock fabric and depositional facies. Within Section 15, wells from the same reservoir have yielded widely varying amounts of total production, further demonstrating even smaller scale heterogeneity.

Inflatable impression packers are not new; they have been around for a number of years.1"2"3 However, their use has been very limited, probably due to one or more of the following limitations: 1. High differential pressure was required to squeeze impressionable material into cracks or perforations, which necessitated an inflatable packer which was expensive to manufacture and difficult to make longer than about 10 feet. 2. The inflation pressure often had to be held for up to 10 hours in order to be able to retain an impression. 3. The inflatable packer had to be returned to its manufacturing plant to be repaired or redressed. A new field-redressable, 30-ft long, low differential pressure inflatable impression packer system has been developed. Also, new impression materials which are oil resistant and which can make and retain in situ impressions in 10 minutes or less have been developed.4 During the development and field testing of this inflatable impression packer system, the minute detail and consistency of the impression retrieved on the new impression material suggested that, with careful calibration, accurate correlations could be made between impression size and actual in situ hole size. Further investigation indicates that the amount of impression material extruded into a perforation. This paper originally appeared as SPE 5707 and is reprinted here through the courtesy of the Society of Petroleum Engineers. under a head of noncompressible fluid is proportional to the formation permeability connected to the perforation. This paper describes the eight critical parameters which must be known and/ or controlled to calibrate impression size to actual size and extrusion height to effective connection to formation permeability in situ.

The unprecedented rile in the cost of tublar goods has made operators look for cost-effective ways to extend tubing life. Fasken has found that using poly lined tubing in rod pumped, injection and disposal wells has been a good option in reducing well failures as well as extending tubing life. Installing a poly liner over damaged IPC tubing is one example of using this liner system and has also been successful in several other applications.

For the past few years there has been a lot of effort expended on examining potential electrical cost savings in the oil field. This paper presents efforts to examine the electrical savings in rod pumping operations by: 1. Motor changes and downsizing 2. Reversing the direction of rotation 3. Changing well operation run times and frequency 4. The effect of installing a down hole gas separator All of these operational changes are inexpensive and the electrical cost savings compared to cost of making the changes are discussed.

From its first development in the early 1960's an effort has been made to optimize a stimulation procedure for the Canyon Sand formation in Southwest Texas. Many attempts have been made to find a fluid system that would maximize stimulation results while minimizing treatment cost and formation damage. As a result, a variety of fluid systems have been pumped consisting of a wide range of both fluid and proppant volumes. This paper investigates historic stimulation practices over eight selected study areas. These procedures are then evaluated based on long-term production data in an attempt to identify an optimum treatment size, for each area, in terms of both fluid and proppant volume.

There are various oil and gas fields across the United States that have been producing for over 100 plus years. While each area experiences different types of issues regarding rod failures, tubing parts, paraffin, scale and corrosion issues, many operators struggle with or how to properly treat these issues.
By banding Capillary string to the outside of your production tubing, you can now properly treat with pinpoint inijection to the exact area that needs to be treated.
Starting in April 2013, you will be able to treat your issues with a Capillary string below a tubing anchor with Weatherford's new Capillary Injection Tubing Anchor. By running this system you will be able to pinpoint treat with your chemicals at the bottom of your pump to treat your rods and the inside of your tubing.

Carbon dioxide corrosion studies of oil-well portland cements were initiated using a new microsample technique to determine the effect of carbonic acid on portland cement slurry formulations and to develop a high carbonic acid corrosion-resistant cement for carbon dioxide Enhanced Oil Recovery applications. Earlier results from studies using two-inch API cement cubes showed carbonic acid had essentially no effect on cement after relative short test periods at elevated temperatures. Similar results with two-inch API cement cubes also were reported in recent literature. Because carbonic acid corrosion in cements was difficult to observe and measure using two-inch API cement cubes, a new microsample technique was developed. Use of this new technique, which represents an accelerated testing method, showed oil-well cements undergo a rapid deterioration in a wet carbon dioxide environment. Similar tests with two-inch cubes showed essentially no cement deterioration under the same conditions. Experimental details of this new microsample technique are discussed. Data relating cement strength loss and carbon dioxide penetration depths to cement type and slurry formulation are reviewed. Included in the discussion is a new cementing formulation which shows significant promise as a high carbon-dioxide-resistant, oil-well cement.

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. Case histories of acid stimulation, with production results, are presented covering San Andres and Devonian horizontal wells and deep hot Ellenburger wells. Treatments varied from high rate matrix to hydraulic fracturing operations. Discussed are key issues to overcome in order to obtain an effective stimulation and methods employed, with particular emphasis on zone coverage.

Carbonated waterflooding is an enhanced oil recovery process developed in the early 1950's that may have potential application in several West Texas reservoirs. The process consists of saturating injection water with CO, in order to swell the remaining oil-in-place, and thereby increase the amount of recoverable oil in a reservoir. The process usually involves less investment and CO, demand than miscible CO, flooding. The effects of carbonated waterflooding on equipment material performance were monitored during a two well carbonated water injection pilot test conducted by Amoco Production Company in the Slaughter Field, Hockley County, Texas. Stainless steel and aluminum bronze material showed no deterioration during the test period. However, severe problems were encountered at holidays in the internal plastic coating of carbon steel pipe and fittings. Injection well material performance data and observations are presented to support these findings. In addition, the surface equipment design used to saturate injection water with CO, will be presented. No attempt will be made to discuss the impact of carbonated waterflooding on injection well or reservoir performance.

Shortages of drill pipe have hit the industry hard for the past few years. Not only has there been a lack of availability of pipe, but costs to replace discarded strings and strings for new rigs have risen sharply. Therefore, the subject of proper care and handling of drill stems becomes increasingly more important. Owners and users must get maximum life with a minimum of problems for their drill strings. Much has been done to increase the life of drill strings, but much more can be accomplished with a broader understanding and practical approach to proper care of drill stems. Although the subject of care and handling of drill stems is not new to the industry, it must be recognized that new people enter the industry every day. How well they are trained and acquainted with possible drill stem problems and the proper care of drill stems will have a direct effect upon the life of a drill string. Therefore, one of the most important steps in proper care and handling of drill stems should be to assure that all personnel associated with using and handling of drill stems are knowledgeable as to why drill strings deteriorate. Most drill pipe degradation, including tool joints, can be categorized into four broad groups: fatigue, corrosion, mechanical damage, and wear.

Manufacturers attempt to deliver sucker rods to the user in the same condition as when they left mill. The processes of unloading, storage, and transportation to the field must be just as carefully carried out, since carelessness at any of these stages can nullify the efforts made at any other stage.

The sucker rod manufacturers are fully cognizant of the fact that sucker rods are required to fulfill one of the most stringent tasks that is offered by today's petroleum producing program. In an effort to combat this challenge the industry has solicited the full support of this nation's great metallurgical research capacity. However, basic steel and steel alloys are merely the initial step toward an end, and the responsibility of providing the necessary medium is entirely the responsibility of the manufacturer, and the degree of responsibility lies with each individual manufacturer. The capability, integrity and reputation of the manufacturer is entirely reflected in his eventual product.

Your injection pump is the heart of your water flood or saltwater-disposal injection system. We, realizing the necessity of continuous injection in a flood, will attempt to pass on information based on past experience and observation that will aid, through proper maintenance, to keep your pump in operation.