Oil and gas producers are frequently faced with deep, low volume applications that challenge today's rod pump technology. There is a growing demand for a reliable form of artificial lift in deep, low volume, hot and aggressive applications. Operators with low volume applications that suffer from deviated well bores or applications that are just too deep and challenging to achieve long run times with a conventional rod pump can now utilize electric submersible pumps (ESPs) as an economical alternative. Historically, low volume submersible pump designs consisted of production ranges greater than 300 bpd. Those submersible pumps had narrow vane clearances, which plugged up easily, had limited gas handling capabilities, limited thrust washer areas and lower-pressure housings. This created unsafe operating conditions and limited
application ranges. New technology such as wider vane stage designs, ultra high pressure housings, higher efficiency gas separators, high temp motors and reliable down hole sensors have greatly contributed to the success of ESP's in this type of application. This paper will present technological innovations and improvements that created the opportunity to utilize ESPs in low volume, deep applications.

How lease capacitors reduce current and line losses on oil field leases is demonstrated. Information from field testing with bottom-hole heaters is presented. Use of timed restarters and heating cable on oil field leases is discussed.

An extensive electrical and mechanical testing program has been performed on beam pumping systems in six producing properties in the Permian Basin of Texas. The subject properties are waterflood or carbon dioxide (C02) flood projects which produce from the San Andres formation. The effect of motor torque mode setting and direction of rotation was studied in 30 wells. The impact on important operational indicators such as electrical lifting cost, gear box loading, and rod loading are addressed. It should be noted that much of the data used in this paper was the subject of a paper entitled "Application of Real-Time Measurement of Motor Power to Determination of Beam Pump Efficiency" which was presented at the 1994 Southwestern Petroleum Short Course. Because more data has since been obtained, the conclusions below are more statistically significant.

This paper will present and discuss the selection, design, construction, and protection of several different types of oilfield-oriented overhead electrical power distribution systems. This information will assist in choosing, installing, and/or modifying the overhead distribution system most suitable for a particular project.

This paper discusses a recently implemented electrical load shedding program at the Salt Creek Field Unit (SCFU) in Kent County, Texas. The project involves the interruption of SCFU electrical load during the wholesale utility's monthly peak load. By interrupting SCFU load during the utility's monthly peak, the SCFU electrical demand charge is reduced by $7.16 or $6.03 per interrupted kilowatt, depending on the time of year. A dual demand electrical rate schedule makes the load shedding concept possible. With this rate schedule, the demand charge is divided into two components. One demand charge is based on the highest SCFU electrical load during the billing period while the other is based on the SCFU load during the wholesale utility's monthly peak. The goal of the load shedding program is to interrupt SCFU electrical load at the time of the utility's peak load thereby reducing one component of the demand charge. A critical element to the load shedding program is the ability to predict when the wholesale utility's monthly peak load will occur. The utility's system load is highly dependent on the temperature in the utility's main load center which is located in and around Stephenville, Texas. By closely monitoring the utility's load and temperature/weather data in Stephenville, the time of the utility's peak load can be forecasted. Historical load and temperature/weather information are also utilized in peak load forecasting. Another key element is the selection of SCFU electrical load to be interrupted during the utility's monthly peak. Currently, high pressure injection pumps and artificial lift installations are interrupted for load shedding purposes. Since the interruption of artificial lift installations results in deferred production, wells must be carefully prioritized for interruption so that lost revenue is minimized. Also, limiting total interruption time and frequency during each billing period is very important in minimizing lost revenue and cycling of lift equipment. Net profit of load shedding each artificial lift installation is determined by subtracting potential lost revenue from potential electrical savings. This paper addresses the electrical rate schedule design, wholesale utility load forecasting, load shedding methodology, and results of the program to date.

The basic configuration of the Electrical Submersible Pump was conceived over fifty years ago. It was originally designed for the traditional vertical well. Development of steerable drilling tools and "measurement while drilling" techniques over the last two decades has allowed drilling wells that radically depart from tradition. To be able to derive the maximum benefit from these complex geometry wells it is necessary to understand some of the production problems and the limitations of the-Electrical Submersible Pump. The traditional well has been thought of as being straight and vertical, however the exact path of the bore hole has never been straight nor vertical for very far. Different physical properties of the rock and the angle at which the bit intersects the formation can cause the bit to skip or dig, producing an infinite variety of bore hole paths. The severity of the deviation from a straight hole is called "dogleg" and is expressed in degrees of deflection per 100 feet of measured hole (fig. 1). Modern drilling techniques allow the bore hole to be purposely deviated, or steered, in order to intersect the producing formation in particular location and manner. These complex geometry wells can be divided into two major categories, the directional wells and the horizontal wells.

The following is an update to an earlier paper compiled and presented in April 1991 at the ESP roundtable held in Houston, Texas. This paper contains referenced categories of problems that have been encountered in field operations and the solutions that have been found to the problems. The discussion for each problem/solution set is brief, but serves as an index to the particular reference, where more detail can be found. The discussion is restricted to field cases. Many excellent studies such as design techniques and recommended procedures are not covered since they are not in the context of a field study containing problems and solutions. Also, some field operational papers were not included if they presented identical information. This study was originally intended to be review of the field cases and a summary of various failures and their causes as a function of the conditions present. However, when beginning to review the papers in the literature, it became obvious that it is rare for a given paper to list detailed field conditions. In fact out of the fifty or so references examined here, only a few contained sufficient field condition data which would have allowed problems and solutions to be correlated to conditions. In addition to categorized and referenced problems and solutions, new innovations, products and operating techniques are presented.

This publication presents a non-technical discussion of the dynamic forces currently active in the petroleum industry. These forces mandate, the implementation of electronic systems to monitor, optimize and control the production of petroleum products. Once the producer comprehends these dynamic forces and their impact, the latest tools available will be discussed. The information presented will enable the reader to gain an over-view appreciation of these tools and how they will provide needed functionality for today's known challenges and tomorrow's unknown requirements.

An expository account of the elements of reservoir simulation in computers is presented for those who wish a review of or an introduction to the fundamental concept. The discussion is related to a concrete problem involving a slightly compressible fluid in a linear medium in order that the methods and results in backward and forward difference techniques can be fully displayed and compared.

In discussing contracts for purchasing or selling gas, some emphasis should be placed on the various provisions of the agreement, but more so on the type of deal that has to be made in order to purchase gas, and on the parts of the contract which have a direct economic effect on the contracting parties. This emphasis should be made when one considers what a changing, dynamic business the energy industry now is. This is brought out now to emphasize how very important the matter of gas contracting is in today's business. Certainly, with the enormous sums of money involved in the purchase and sale of gas, the significance of the legal instrument covering that transaction must be recognized. It follows that there is an added importance in the measurement and accounting for the product being sold and for the proper operations under the contract.

Empirical oil recovery forecast models were developed for waterflood infill drillings in San Andres and Clearfork carbonate reservoirs of Permian Basin. The models were developed using field waterflood databases and the geographical distributions of the ultimate recovery efficiencies. The study evaluated the incremental oil recovery by infill drilling without acceleration of expected oil recovery. Results of testing the empirical oil recovery forecast models indicated an average error of less than six per cent. The forecast models are applicable to a wide range of unit sizes. They are useful for initial evaluations of waterflood infill drilling performance and for property evaluation. The dominant factors affecting the infill drilling ultimate recovery are found to be primary ultimate recovery (geology, pay connectivity, rock properties, etc.), well spacing and development strategies. When the well spacing is to be reduced to below 20 acres, a targeted infill drilling based on reservoir geology, reservoir properties and past production performance should be contemplated instead of a blanket pattern infill drilling.

Encapsulated breakers for water-based fracturing fluids have been widely used for the past decade. These breakers provide a delayed break because the reactive chemical is separated from the fracturing fluid by a water-resistant coating. Higher breaker concentrations can be used, resulting in improved proppant pack conductivity. However, the coating is not completely impermeable. The breaker material can release through the coating under certain conditions when placed in an aqueous environment. This paper shows the breaker release rate as a function of temperature, hydrostatic pressure and aqueous fluid pH. A breaker release apparatus was developed, and tests were performed from 150_F to 225_F, 0 to 8000 psig, and fluid pH of 4, 7, and 9.5. The major findings were that the breaker release rate is a very strong hnction of pressure and temperature, but is independent of aqueous fluid pH. Fifteen percent of the encapsulated breaker is released after 6 hours at 150_F and 0 psig, whereas only 8% and 7% of the breaker is released at 2000 psig and 8000 psig, respectively. Sixty percent of the breaker is released after 1 hour at 225_F and 500 psig, while the 8000 psig breaker release is 12% after 1 hr. These findings suggest that tests evaluating the stability of fracturing fluids at low hydrostatic pressure conditions (such as using Model 35 or Model 50 rheometers) do not represent the actual breaker performance under fracturing conditions. Breaker schedules based on these low-pressure tests underuse encapsulated breakers and jeopardize the proppant pack cleanup process. Using the correlations developed in this study, it is possible to calculate the wellsite breaker schedule from lowpressure rheology tests using encapsulated breakers. Polymer-induced fracture damage will be reduced and well productivity increased.

Very little emphasis has been placed on conservation in lease crude oil processing to date. This subject was not a practical consideration until about a decade ago when the value of the energy products began to rise. Since new-oil price decontrols instituted ten years ago, crude oil has risen in value one thousand percent, and natural gas as high as 500,000 percent. This, of course, has whetted our economic appetite to produce and sell more. But even today very little consideration is given to the economics of conserving what we already have. Conservation is lack-luster when compared to the excitement of wildcatting. And yet, conservation is a sure thing. As little as 5% conservation across-the-board could reduce our import oil requirements by over 10% without the speculative gamble or huge capital costs of wildcatting. A grass roots approach to conservation is conservation in the processing of lease crude oil.

Many stripper wells under beam pump operations are operating at or near the economic limit and, without application of available technologies for improved operation to reduce lifting costs, these wells are candidates for abandonment. This possible abandonment creates significant opportunities and challenges for domestic oil operators. A major operating expense is energy cost which requires the operator to maximize energy efficiency. This requires the technical expertise in identifying methods to optimize operations and technologies to increase energy efficiency in field operations. The objective of this paper is to describe 1) typical operating expenses in domestic oil fields, and 2) a procedure to identify areas where energy usage could be reduced in an oil field or well. The procedure is broken down into non-field and field activities. It describes a screening procedure to determine if operators have candidate wells and oilfield systems where electrical efficiency can be improved. Topics addressed are 1) power tariffs and marginal well service riders, 2) power factor, 3) rate and demand reduction, and 4) improved efficiency through proper motor sizing.

This paper presents a review of performance evaluation tests for various types of engine lubricating oils with significance of performance tests evaluated for specific operating conditions.

This paper presents the basic concepts of systematically engineered selections of submergible electric pumping systems. The adaption of the basic design principles to a number of different application concepts is reviewed and the effects on pump performance of produced fluid properties, particularly viscosity and ingested free gas are discussed.

A brief history of the 6400 foot Huff Sand Reservoir, Sadler, West (Pennsylvanian) Field, Grayson County, Texas, is presented. Primary production history, predicted and actual water flood production, reservoir properties, pattern selection, and operating problems are discussed. The simultaneous use of fresh and saline waters, conversion from beam to hydraulic pumping units, and reasons for premature flooded oil production rate decline are included.

In the last two years, the oil and gas industry has seen an increase in the use of resin coated proppants in hydraulic fracturing treatments. Resin coated proppants are now used routinely in a wide range of reservoir conditions. This paper will examine several key issues which should be considered when using resin coated proppants. 1. Operational procedures and problems encountered with resin coated proppants. 2. Treatment design parameters with resin coated proppants in low and moderate temperature reservoirs. 3. Fracturing fluid compatibility with resin coated proppants. 4. Laboratory and on-site quality assurance and quality control tests to ensure fracturing fluid compatibility and performance with resin coated proppants. A standard method for testing proppant compatibility with fracturing fluid systems will be presented. Quality assurance and quality control procedures for proppant compatibility with fracturing fluid systems should include the above method.

In the last two years, the oil and gas industry has seen an increase in the use of resin coated proppants in hydraulic fracturing treatments. Resin coated proppants are now used routinely in a wide range of reservoir conditions. This paper will examine several key issues which should be considered when using resin coated proppants. 1. Operational procedures and problems encountered with resin coated proppants. 2. Treatment design parameters with resin coated proppants in low and moderate temperature reservoirs. 3. Fracturing fluid compatibility with resin coated proppants. 4. Laboratory and on-site quality assurance and quality control tests to ensure fracturing fluid compatibility and performance with resin coated proppants. A standard method for testing proppant compatibility with fracturing fluid systems will be presented. Quality assurance and quality control procedures for proppant compatibility with fracturing fluid systems should include the above method.

Through the years there have been wells in which lift efficiency has been sacrificed because of the interference of gas from the producing formation. This problem is still prevalent today; in fact, it appears that it will be further complicated in some areas by the development of steam floods which may necessitate producing wells fluids containing water vapors and emulsified crude oil. It is the intent of this paper to discuss the suitability of the various methods of artificial equipment for producing gaseous fluids. The effect of such fluids on lift efficiencies will be included along with applicable operating arrangements and recommendations for obtaining satisfactory equipment performance.

Fracturing has always been regarded as a highly technical type of stimulation treatment, and even the earliest fracture jobs were performed under carefully controlled conditions. A large number of variable factors controlled the efficiency and ultimate success of any treatments. During the past ten years of field application, the greatest emphasis has been placed upon only two or three of these variables. Failure to observe all pertinent factors has, in some cases, caused considerable disappointment and economic waste. An engineered "Frac-Guide" has now been assembled which allows preplanning treatments for improved results. This is accomplished by proper evaluation of the many variables present on every job.

Engineers have become the principal source of management material in the petroleum producing industry with

Texaco E & P Technology Dept., under the supervision of Dr. Dale Brost, has developed Oil-in-Water (OIW) Monitoring Systems. This five year project was initiated to provide an on-line monitoring system that would be instrumental in providing clean water to address the environmental issue, reduce chemical costs in water treating systems, provide recorded water monitoring every second of every day, and set off alarms. Based on this research, the EOA (Environmental Oil Alert) OIW monitor, (fluorescence method) was developed through joint efforts by Texaco and Houston Photonics, Inc. Through continuous research, an additional on-line monitoring system, the SpectraScan OIW Monitor. An absorbance method for running oil-in-water ppm, was developed. The SpectraScan OIW Analyzer for bench top analysis was also developed to replace the freon solvent extraction method (IR) of running oil-in- water ppm. A major producer in the Permian Basin would have had the capability of reducing the $3.3 mm spent annually on injection well work-overs and filter media replacement with the use of a OIW on-line Monitor. In conjunction with the savings, the effectiveness of the CO2 water flood would have been greatly enhanced.

This paper presents the potential for enhanced oil recovery, the processes by which this potential might be realized and the pertinent economic considerations, with special emphasis on the Permian Basin. Of the more than 440 billion barrels of oil that have been discovered in the continental U.S., approximately 300 billion barrels will be left in the ground after primary and secondary recovery methods are terminated. Although not all of the remaining oil can be recovered by enhanced oil recovery methods, as much as 39 billion additional barrels can be extracted using currently available technology. This paper will discuss the potential for enhanced oil recovery in the Permian Basin and the most technically and economically feasible methods for its recovery.

The petroleum industry is faced with a problem in the near future: what does it do about environmental hazards that accompany hydrocarbon exploration and production. The industry as a whole, is currently doing a very good job of environmental housekeeping, but has a bad public image as the keepers of the environment. The best environmental policy for the petroleum industry is first educate ourselves in the compliance laws and the best environmental policies, and second to transfer this knowledge to the general public. To begin this educational process the first step is to understand the laws governing our activities. The environmental concerns for the operator of production facilities, both existing and proposed, will be discussed. The discussion will begin with an explanation of what is meant by the "no net impact" concept of operations. A general outline for compliance with environmental laws and regulations will be presented. This outline will begin with the permitting process and continue to cover such topics as air pollution control, water pollution control, underground injection control, and hazardous waste management. Federal regulations and state regulations of both Texas and New Mexico will be the focus of the discussions.