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.

Several operational changes have taken place at Block 31 to reduce operating costs and increase revenue. The most significant change has been the utilization of waste heat for treating oil emulsions. This has resulted in increased gas sales by reducing fuel gas requirements, a reduction in operating costs, and the elimination of a potential safety hazard. Computerized test equipment has been installed to provide more accurate testing, which in turn has provided improved data to assist in the management of the reservoir. A plunger gas lift system is being used to improve lift efficiency and to reduce operating costs.

Federal regulation of prices charged by producers of crude oil was based on a "property" concept focusing on the "right to produce" as it existed in 1972, which the Department of Energy (DOE) and its predecessor, the Federal Energy Administration (FEA) attempted to define and clarify through numerous Rulings, Interpretations and Decisions. Producers often faced substantial liabilities in the context of compliance actions by the Economic Regulatory Administration of the Department of Energy by reason of their failure to designate properties in accordance with Department of Energy Regulations and Rulings. By the same token, however, Producers often failed to take advantage of the substantial flexibility inherent in the DOE property definition. Unfortunately the ambiguities, interpretative problems, uncertainties and risks which have attended property determinations and designations under crude oil pricing regulations did not cease to exist on January 28, 1981, when President Reagan signed an Executive Order removing all federal price controls on crude oil. The Crude Oil Windfall Profit Tax Act of 1980 relies upon and incorporates by reference the Department of Energy regulations as they existed in June, 1979, for purposes of determining the appropriate taxation tier for crude oil-- "without regard to decontrol of oil prices or any other termination of the application of such regulations. The term "property" which was the pivotal concept in determining whether crude oil qualified as "new oil," production from a "stripper property" or "newly discovered crude oil" under the June, 1979, regulations has been defined in Section 150.4996-I of the excise tax regulations under the windfall profit tax as having "the same meaning as that term is given by the energy regulations. Just as a failure to understand and properly apply the property definition under price regulations resulted in substantial over or undercharges by producers, such failure could result in taxation at an improper tier under the Crude Oil Windfall Profit Tax Act of 1980, resulting in some instances, in taxation of crude oil production at substantially higher rates under one tier than would apply under another tier for which the production could also properly qualify. The following discussion is intended only to point out the factors involved in a property analysis and is not intended to serve as a complete guide to property determinations.

Water soluble polymers find three major applications in oilfield enhanced oil recovery projects. Two of these applications involve reservoir fluid mobility control while the third involves profile control via reservoir heterogeneity modification. All polymer applications in the oilfield require certain operational practices to ensure that the polymers can function as designed. Many of the design criteria involved in polymer applications include production and injection equipment modifications in conjunction with reservoir fluid chemistry considerations. Finally, the proper choice of specialty chemicals to support injection and production of oilfield polymers is essential to the ultimate success of the projects. Two types of polymers are used in oilfield applications, the hydrolyzed polyacrylamides and the xanthan polysaccharides. Although each have their own specific advantages and disadvantages, the injection water quality requirements are essentially identical for both polymer types. A combination of specialty chemicals and specialized equipment is often required to meet the strict water quality requirements. In any system compatibility of all components is essential. This paper will discuss the water quality requirements and the problems involved in designing a compatible system. On the production side of polymer applications, compatibility is again of paramount importance. Saleable oil can only be attained if emulsions that are stabilized by the interactions of polymer, surfactants, solids, water, oil and bacteria can be resolved. Obtaining disposable or reusable water while minimizing produced fluid corrosivity is also a major consideration. Once again, systems must be designed that can effectively employ specialty chemicals (e.g. demulsifiers, water clarifiers, corrosion inhibitors, scale inhibitors, biocides), and mechanical techniques that minimize operational problems.

This paper points out some of the operational difficulties that may arise in water flooding and shows major factors which must be considered to arrive at a solution to the problems.

This paper is presented to clarify a few of the general problems encountered in water flood operations. The production personnel are responsible for the production of the water supply wells, operation of a water plant and distribution system, and supervision of water injection wells. These duties are in addition to their usual occupation

The recent growth in applications of a new carbonate stimulation technique, which involves the construction of numerous tunnels or short laterals out of a main wellbore by using coiled tubing, has yielded excellent production improvements. A simplified mathematical model to analyze this acid stimulation process is presented in this paper. From the perspective of reservoir properties, this simulation takes into account the reservoir heterogeneity, drainage size, permeability, fluid characteristics, porosity and skin factor. From a tunnel construction perspective, the simulation considers the influence of acid jetting angle, tunnel geometry, tunnel numbers, and eccentricity in different pay zones on well productivity. Meanwhile, from an acidizing viewpoint, the simulation considers effects of acid concentration for tunnel initiation and extension, rock solubility, and acid spending. These capabilities guide job design and reservoir performance analysis in field operations. As an example, a comparative study of different tunnel configurations for optimizing production is provided.