The routine use of minimum density cement slurries (4-11 lb/gal) in oil field applications has been limited in the past; primarily because no convenient, cost-effective process existed which could provide useful compressive strength development at low densities. The careful selection and use of surfactants and foam stabilizers in addition to the use of properly designed field equipment has enabled the mixing and placement of stable foam cement slurries with instantly variable, but controllable downhole slurry densities from 3.5 - 14 lb/gal over a wide range of conditions. Typical physical properties such as compressive strength, porosity, and permeability for foam cements of various densities are presented. Foamed cement slurries have been successfully applied in the oil field on squeeze jobs, leaking LPG underground reservoirs, salt-zone wash-outs, as well as primary cementing jobs. Job histories covering 31 field jobs will be discussed.

There are approximately 600,000 producing crude oil wells in the United States, the majority of which use electricity to meet their production needs. Of these wells, approximately 75 % are classified as "Stripper Wells", producing an average of 2.34 barrels per day [I]. Many of these wells are only marginally economic, and an efficiency improvement project may make the difference between continuing to extract oil from a well and having to shut it in. In addition to the pump jacks, electric motors are used for water injection, pipeline pumping, steam production, and other operational necessities. In all, roughly 95% of all electricity used in an oil field operation goes into operating electric motors. The University of Wyoming Electric Motor Training and Testing Center (WEMTTC) has conducted an extensive study of electric motor efficiency at the DOE's Naval Petroleum Reserve #3 in Casper, Wyoming. Approximately 500 motors were tested for operating efficiency, many of which were determined to be oversized and operating inefficiently. This paper discusses the test method and instrumentation developed by WEMTTC, estimated results for energy-efficient motor retrofits. and actual results of several retrofits. The economic benefits of the retrofits are discussed, as well as a protocol for improving electrical energy efficiency in the oil field.

Lightning damage costs the oil industry millions of dollars each year in lost production, replacement equipment and service. Simple compliance with the National Electric Code is not sufficient because oil field operations involve concentrated electrical loads widely separated from each other. To efficiently serve these loads three-phase power is typically distributed at 12,470 volts. Installing lightning arresters only at poles having or feeding equipment is simply inadequate. Ground resistance, ground lead inductance, lightning arrester connections, power system grounds, shield wires, slack spans, ground bonding and transformer connections should all be considered in a comprehensive lightning protection plan. The intent of this paper is to strive for some consensus in equipment connections and grounding techniques which will produce the best reliability in rod and sub pump operations.

Types of plastics available, their uses and mis-applications. Quality control of plastic materials and the applied coatings.

Flow back and produced waters in the oil field are heavily laden with contaminates including insoluble iron sulfides,
poisonous hydrogen sulfide, residual gels, friction reducers, and other chemicals. In this paper we will look at chlorine dioxide (ClO2) as one possible solution to these problems. As a powerful, yet selective oxidizer, ClO2 has the ability to break up the residual gels and friction reducers while removing the insoluble iron sulfide and killing the hydrogen sulfide. As an additional plus, ClO2 is an EPA approved biocide that kills the bacteria which are the root cause of many of the problems with water reuse.

A system is described which utilizes a strain gage dynamometer permanently attached to each well for sensing well operation. The system also utilizes standard aerospace telemetry techniques and telephone lines for gathering the well data to a central office where individual wells performance may be monitored and simple control functions provided.

The year of 1976 represents a milestone for Amoco Production Company as they complete a decade of experience in computer-controlled oilfield automation. Table 1 presents a summary of percentages of wells and production being received by automation projects which Amoco had installed as of the first of this year and what they currently estimate their position in automation to be within the next five years. As can be seen, as of January 1,1976, Amoco had 35% of its company-operated oil wells and 6% of its company-operated gas wells automated and under computer control. These wells produce 49% of Amoco's company-operated gross oil production and 19% of its operated gross gas production, respectively. In addition, 25"-% of the injection wells in Amoco-operated secondary recovery projects were automated at the beginning of this year. These automation projects are located throughout Company operations including Canada, the Rocky Mountains, Oklahoma, Louisiana, (onshore and offshore) and Texas. Within the next five years, Amoco expects to have 58% of its company-operated oil wells and 21% of its company-operated gas wells automated. These wells currently produce 78% of Amoco's company operated gross oil production and 44% of its operated gross gas production. It is further anticipated that 79% of the injection wells in Amoco-operated secondary recovery projects will be automated.

As most of the energy companies struggle to remain competitive in the domestic market, one of the costs which seems to continue to climb is the cost for electricity. For some operations, these costs can represent as much as fifty percent of the operating costs. To continue to operate in the domestic market, it is imperative that energy companies explore all avenues for reducing this cost to a minimum level. Mobil Exploration and Producing U.S., has entered into a contract with Brazos Electric wherein Brazos Electric will purchase 40,000 kilowatts of Mobil's Salt Creek Field Unit electrical demand, for $25 per kilowatt, or $l,000,000per year for two years. This paper will discuss the details of this contract and cover the history of the electrical cost reduction methods used at Mobil's Salt Creek Field Unit which led to this agreement. These efforts have combined to reduce the total electrical costs from $0.06/KWH to today's price of $0.0365/KWH.

A properly engineered project requires the use of accurate and reliable data. So it is with the design and selection of submersible pumping equipment. In order to gain maximum benefit from any submersible pump installation, one should make efforts to acquire the best possible quantitative and qualitative data available. Such factors as static and working fluid levels or static and producing bottom-hole pressures are vitally important as is knowledge of well and fluid conditions such as the ambient temperature down-hole and the corrosiveness if the fluid. Such conditions dictate the approach to an enlightened selection of equipment. Submersible pumps are not without limitations and the effect of these limitations is better understood with knowledge of the conditions under which the equipment must operate. A certain degree of flexibility is offered by submersible pumps in that they can be applied in a variety of ways in meeting high-volume pumping problems. Practically all oilfield applications are found to be in either water supply wells for waterflood projects or in high water-oil ratio producing wells. The latter may be in natural water-drive reservoirs where much primary oil can be gained or in waterflood producing wells where high volume pumping is required for maximum flood efficiency and greater ultimate recoveries.

This paper discusses the basic principles by which computer-automation-systems and devices are operated. Some of the topics discussed included go/no-go devices, thermocouples and thermistors, piezoelectric devices, strain gages, potentiometric transducers, linear voltage differential transformer applications, the force-balance principle, and digital output transducers.

Admixtures of 50:50 Class H (or Class C): Pozzalon with 2% bentonite have functioned effectively worldwide for almost 50 years as lightweight slurries, for situations where heavier completion cements posed a risk of exceeding low fracture gradients in a particular wellbore. Pozzolanic materials are lightweight, and effectively combine with calcium hydroxide that is liberated during the hydration of portland cement. But there have been two disadvantages to the 2% bentonite utilized to assist in the specification of relatively high water-to cement ratios: First, its presence in typical cement slurries reduces the effectiveness of a given concentration of most commercially available fluid loss additives. Second, while the 2% (by weight of cement) volume may seem of no consequence, the shipping costs associated with moving tons of the material over a long period of time can be significant. Extensive testing of 50:50 slurries revealed that small quantities of sodium metasilicate (on the order of 0.5% by weight of cement) could effectively replace bentonite. Free water was controlled to the same degree, and a synergy with a commonly available fluid loss additive was discovered, allowing either a) less total fluid loss additive for a given fluid loss control tolerance, or, b) better fluid loss control for a given concentration of fluid loss additive. This project was undertaken to determine whether or not there were other commercially available materials that could substitute for bentonite

A quality control survey of 162 acidizing fluids revealed the following problems: 1. Acid concentrations were often too high or too low. 2. Frequently, fluids were not thoroughly mixed. 3. In some cases, fluids contained incompatible additives. A field test kit and conventional laboratory analyses were used to determine the acid concentrations in fluids from 44 acid jobs done in Southern California during the last four years. On 41% of the jobs, the acid concentration of at least one fluid varied more than 30% from the specified value. The quality of the fluids from five service companies were surveyed; however, just two companies did 77% of the jobs. Analyses of iron content in the acids showed that 78% of the fluids contained less than 200 ppm iron. The average iron content was 180 ppm. The test kit assembled for this survey permits rapid well-site analysis by people who do not have formal training in chemistry. The total analysis time is about 2 minutes each for HCl and HF and 5 minutes for the iron analysis. The concentrations of HCl and HF are determined volumetrically by using constant volume dispensing bottles rather than a buret. A novel method is used to titrate for HF directly. A commercially available kit is used to measure the iron content of the fluids. The high percentage of jobs where acid concentration varied more than 30% from the specified value suggests that analysis of acid concentrations is a necessary part of any acidizing program. The test kit described here permits the simple and rapid analysis required for a successful quality control program.

The recent trends in the use of on-site computers to calculate bottom hole treating pressure has created a need for a better understanding of insitu fracturing pressures and treating fluid friction properties. This paper discusses several Permian Basin fracturing operations with special emphasis on optimum pressure monitoring procedures. The theories of critical pressure, height growth, closure pressure and formation heterogeneity are discussed in an effort to provide techniques for on-the-job interpretations. Actual job examples have been presented with analysis and discussions. The analysis of net pressure frequently presents several problems unique to the formations and fields of the Permian Basin area. This paper analyzes those problems and provides on-the-job solutions and alternatives.

Removal of calcium sulfate scale from wells is presently accomplished by several methods including scraping and chemical treatments. The most widely used chemical methods employ either: 1) a time-consuming and moderately expensive two-step conversion/ acid dissolution process or 2) a very slow reacting and expensive, alkaline chelating agent treatment. In an effort to lower the overall scale removal treatment cost and circumvent the objectionable qualities of the commercially available chemical treatments, a one-step calcium sulfate scale removal technique has been developed and successfully used in over 100 wells. This remedial technique has been employed to increase injectivity in injection wells, increase production in producing wells, and open up perforations to permit more efficient primary stimulation or remedial treatment of producing zones. Treatment costs range from $2000 to $5000, depending on whether or not additional primary stimulation or remedial treatment fluids are to be incorporated with the calcium sulfate scale removal fluid. Post-treatment production increases have ranged from 50% to 10 fold and treatment payout has typically required 30-45 days of post-treatment production.

This paper will present case histories from openhole horizontal completion projects using a new hydrajetting fracturing process to place multiple fractures in openhole. The new hydrajetting factruing method can be applied to cased or openhole situations, and does not require mechanical isolation between treatment points. The method works well with both acid and proppants fracs. The case histories will illustrate recent improvements in coiled tubing equipment that have made it possible to reduce the completion cycle time, and safely perform coiled tubing equipment that have made it possible to reduce the completion cycle time, and safely perform coiled tubing fracturing with proppants in an openhole horizontal setting.

Dramatic change in the economic climate of the petroleum industry over the past year places a demanding challenge on oil producers to achieve positive cost effectiveness in their producing operations. Overall lifting costs for artificially lifted wells will be a significant factor in meeting this challenge. A new long stroke sucker rod pumping system has been developed which offers benefits to deal with these cost factors. Performance results to date confirm reduced energy consumption and improved pumping performance.

The North Cross Devonian Unit is located in the Crossett Field at the southern edge of the central basin platform in West Texas. The reservoir is a chalky, siliceous carbonate with 21% porosity, 3 md permeability and has an average pay thickness of 90 feet. There are 17 producers, 6 CO, injectors, 3 residue gas injectors, and 2 TA wells in the unit (Fig. 1). In 1964, residue casing head gas injection was started to" maintain reservoir pressure, and CO, injection was begun in 1972. Response to CO, injection occurred in one well early in 1973 and by late 1974, four wells were showing signs of response. As of the end of 1974, the unit produced 56,000 BOPM, with a GOR of 8000. Figure 2 shows the unit's performance since 1964. To date, the only major operating

This paper is divided into two sections-the first covering a discussion of the types of prime movers
used in the oil fields, their cooling systems and ignition. The second part covers fuel systems, lubrication
and general maintenance items. Almost all types of prime movers have been used at one time or another in the oil fields. Some of these have proven satisfactory, but many others have been discarded in favor of more acceptable types of equipment. Before we can properly operate and maintain oil field prime movers it is necessary that we understand the basic operation of the engine or motor. There are four basic types of prime movers used in the oil fields: (1) Electric motors. (2) Four cycle high speed multi-cylinder engines. (3) Four cycle slow speed engines. (4) Two cycle slow speed gas engines.

Slow speed pumping engines may be defined as engines of speeds up to 500 or 600 rpm. These engines are generally single or twin cylinder design and may be either two or four cycle.

This paper is a review of the operation and performance of the Goldsmith-Cummins (San Andres) Unit, The Unit is located in northwest Ector County, Texas. It produces from the San Andres dolomite at approximately 4200 ft. The general Goldsmith Field structure is an anticline with two large domes connected by a productive saddle. Gas caps are present in portions of the field. First field production began in 1934." The Unit is operated by Atlantic Richfield Company. It is composed of 191 wells; most wells were drilled and completed prior to 1940. The general completion procedure was to drill to 3900-4100 ft, set casing, deepen to total depth and treat acid and/or short with nitroglycerin. A few of the wells were fracture treated during the 1950's and 1960's to increase production rates.

Secondary Recovery was introduced to the oil field some years ago. One of the most advanced secondary recovery projects to date was "kicked off" by the Atlantic Refining Company on May 9, 1958, on the H.T. Boyd Lease in Slaughter Field, Texas. This project consists of injecting propane, then gas, then water into the San Andres pay. This paper will explain briefly the operation and problems encountered in this Miscible Slug Project.

Factors affecting the proper selection, installation and operation of deep shaft-driven centrifugal pumps. Use in source wells for secondary recovery projects is outlines, especially with reference to temperature and solids content of the supply water.

Hydraulic pumping units are classified as surface or sub-surface. Our discussion refers only to surface units which reciprocate a sucker rod string connected to a sub-surface plunger pump. Hydraulic unites may be classified as counterbalanced or non-counterbalanced. The counterbalance is provided by weights or compressed gas. Our discussion will be based on compressed gas- counterbalanced units and non-counterbalanced units.

The increasing cost of producing oil has caused operators to expend every effort to reduce operating expense. This expense is always increased when an artificial lift is required. The most popular type of artificial lift has been the beam pumping unit. The operation of this type of pumping unit may become very costly without proper care and maintenance of the equipment. Primarily, the responsibility for this operation falls on the field personnel of the oil company. Through training and experience, they have learned the techniques and procedures required for the pumping of individual wells. We would like to discuss the correct techniques and procedures necessary to assure satisfactory operation of this pumping unit.

The operation and maintenance of equipment on pumping wells has always been considered the function
of the field man in the oil business. Primarily this has been true because of the fact that the field man,
through his training and experience, has handled the equipment and learned the techniques and procedures
suitable for the pumping of individual wells under the varying conditions that are encountered. The operation, care, and maintenance of the surface equipment, particularly the pumping unit, is what we would like to discuss here.