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.

Every year petroleum production storage tanks are ruptured, exploded or imploded due to improper vent system design and maintenance. The losses incurred from these accidents are considerable. Additionally, federal, state and local air quality regulations are becoming more stringent and new design considerations are required to meet these standards. This paper reviews vent system design criteria, explosive gas-air mixtures and offers some operational and system safeguards that can significantly reduce the risk of loss due to improper vent system design and maintenance. The tanks considered in this paper are lease tank battery installations as described in API RP 12Rl. The design recommendations are based on API standards, field experience, lab testing and an economical approach to current standards.

Partial or total lost circulation is prevalent in the Permian Basin of West Texas during many drilling and cementing operations. Whether losses are due to highly vugular or cavernous intervals or due to low fracture gradients, the problem is recurrent over the entire region. The common practices for fighting these losses are foamed mud sweeps, foamed cements, lost circulation pills and high-viscosity gel spacers containing lost circulation materials. This paper presents case histories representing more than 100 wells in which a new environmentally preferred system has been employed. Specifically, instances during drilling are discussed where partial or total losses in returns have occurred and have been restored by pumping 40 to 50 bbls of this new material. These same wells after restoring circulation resume drilling to total depth without any further losses. In addition, cases are presented where the system is used as a spacer pumped ahead of cement, resulting in the circulation of cement in an area where this has not occurred before. Another example resulted in the improvement of bonding by the cement. Additional scenarios demonstrate that pumping this material on a single stage cementing job, could replace the normal two stage job.

This paper discusses the methods currently used by Texaco's Midland Producing Division to monitor and reduce equipment failures and chemical usage. The cost effectiveness of the program is readily apparent having resulted in a 50+ percent reduction in the failure and maintenance cost from the first quarter 1986 to the second quarter 1989. The items presented in the paper include the methods of reporting, tracking, and reviewing equipment failures and chemical usage. Included in the presentation are examples of surface and subsurface failure reporting forms, equipment failure data base, chemical selection and testing criteria outline, monthly chemical reporting format, quarterly meeting format, and report of special equipment being tested.

The intended functions of wellbore equipment in injection or producing wells are to provide well control and safety. It is only in a situation where both of these are provided that efficient, trouble free operations can be depended on. Enhanced oil recovery places unique demands on wellbore equipment which must be planned for during completion design. This paper discusses techniques and equipment which can be utilized to provide the necessary well control and safety in carbon dioxide flooding operations. A complete treating of the subject discussing exhaustively the aspects of possible design combinations would require voluminous material not possible in a paper such as this. Therefore it is the authors' intent to discuss what we believe to be very important considerations within the subject and give enough case history information to help the reader set the tone for a comprehensive study of his individual situation.

Ranking high among conditions that reduce well productivity is the deposition of scale and/or precipitant in and around the well bore. These deposits occur in both producing and injection wells and range from silts and soft asphaltines to extremely hard and brittle scales such as calcium or barium sulphate. Methods of removal of the deposits include solvents of all types, chemical converters, mechanical scrapers, high pressure fracturing or wash, and several variations of explosive devices. These various methods, successful to some degree, all have some undesirable side effects and most are significantly ineffective when used on the more resistant scales. A tool for use specifically on these harder, more brittle deposits has been developed, utilizing sonic energy and shock waves to pulverize these scales and facilitate their removal from the well bore. Effectiveness varies with conditions, but results have been more gratifying in areas where other techniques and tools have been the least successful. The tools are in operation in limited supply at present, with a history of approximately 60 operations. Tools, principles, applications, current results, and projected improvements are discussed in this writing. Subsequent results will be made available to the industry as service and histories progress

This decade has seen tremendous progress in ESP cable development that has extended cable run life in even the harshest well conditions, However, as the range of cable offerings has increased to address specific operating conditions, greater demands are placed on selecting the right cable for any given application. This paper explains the crucial drivers involved in selecting ESP cables and summarizes, in straightforward terms, how cable design relates to service performance. Petroleum and Specifying Engineers who want to increase run life and obtain maximum value for their ESP Cable investment will find this paper both interesting and beneficial.

A design procedure is detailed which uses motor performance and electrical submersible pump stage performance corrected to actual pumping speeds with IPR performance. The program then shows what any selected design will produce under various conditions including HZ and surface pressure. The calculations routine is "Nodal" (TM of Macco Schlumberger) in the respect that it will plot expected performance of a given design at either the perforations or at the pump intake; At the perforations, an IPR curve can be checked or generated by using the program output. Pump intake pressure readings can be checked against the program output if the calculated output plot is selected at the pump intake near a downhole pressure instrument. The design is made at one point and operation at a broad band of off-design conditions is made using graphical output. Examples are presented to demonstrate some design considerations that should be examined when considering an application of ESPs in a new area.

An electric motor is similar in some respects to a resistor in that its power rating is a function of the maximum operating temperature of the materials. In electrical apparatus, as far as temperature is concerned, it is permissible to overload the device as long as the safe operating temperature is not exceeded (Ref 1). The temperature of the device is a function of the temperature of its environment and its ability to transfer heat to its surroundings. To be accurate, the horsepower rating of an ESP motor should take this into account. This paper reviews the major factors controlling the generation and the dissipation of energy in a ESP motor and presents a work sheet for approximating the maximum well temperature an ESP motor for acceptable run life.

ESP performance is affected by the presence of free gas. Two-phase performance is sensitive to intake pressure, in situ gas fraction, fluid properties, speed and number of stages. The degree of head deterioration varies from the simple reduction in the pressure increment to surging and gas locking. So far, no reliable predictive method is available to predict the performance of centrifugal pumps under two-phase conditions and to address the problems of surging and gas locking. The University of Tulsa Artificial Lift Projects is currently conducting experimental and theoretical research on the two-phase behavior of centrifugal pumps. This paper presents the analysis of experimental data for two-phase flow performance of a 22-stage centrifugal pump on a stage-wise basis. The tests were conducted at 50 Hz, varying several operating conditions such as intake pressure (50 to 250 psig) and gas flow rates. Comparison of the experimental data from this work with the homogeneous model shows that the homogeneous model is not capable of correctly predicting head degradation, surging and gas locking conditions. This work is fundamental for the development and validation of models or correlations for predicting performance of ESPs under two-phase conditions.

The ESP uses the flow of well fluid to cool the motor. This has been traditionally done by landing the ESP above the perforations, or by using a shroud to redirect the fluid around the motor. This paper presents some of the advantages and disadvantages for below perforation operation. Several options on the equipment necessary for this type of operation are presented along with a field experience of an operator in a location where below perforation operation looked to be advantageous.

With oil prices at an all time low, production companies are making every effort to reduce operating expenses. Much of this reduction is not entirely on cutting production output, but in utilizing available new artificial list technology. Once such technology is ESPCPs; or Electric Submersible Progressing Cavity Pumps. By combining the technologies of both ESPs and PCPs, the operator can reduce their operating costs while increasing the lift system efficiency often resulting in an increase in production. By eliminating the sucker rods used in a conventional PCP application, the frictional losses can be reduced. In the case of heavy oil production, these losses can be substantial and if eliminated, can result in higher system efficiencies and increased production. When compared to a conventional ESP, the overall system efficiency is higher by the pure nature of the pumping technology (centrifugal vs. positive displacement). A prime example can be seen in the ESPCP installation in MPG-202 in the Morichal District in Eastern Venezuela. The producing formation is the Morichal-7. Production is around 1 l 00 BFPD (22% H2O) of 9 degree API gravity oil and the pump setting depth is 3259 feet. The well has a producing GOR of 625 SCF/STB. Prior to its installation on February 5, 1998, a conventional ESP system had been operating. Overall efficiencies of this system were extremely low as a result of the fluid viscosity and free gas at the pump intake. The decision was made to try an ESPCP system as an alternative lift method to see if the production rate could be increased without causing more problems from additional free gas at the pump intake. Once installed, the production rate increased as a result of the increased efficiency of the ESPCP system in viscous fluids. One additional advantage of the ESPCP system is the pump's ability to handle the free gas at the pump intake. Calculations done for intake conditions showed the percentage of free gas at the pump intake to be 45%. This paper will elaborate on the production advantages of installing the ESPCP system in this Eastern Venezuelan heavy oil well.

This is the fifth in a series of papers, which deal with literature on Electric Submersible Pump (ESP) application problems and solutions. All the papers summarize and categorize ESP reference literature by a number of different topics. The objective is to list briefly problems mentioned in various papers and the solutions to those problems, which are detailed in the given references. Originally, there was also an attempt to relate problems to various field conditions, but that effort was dropped because of a general lack of enough application data to accomplish this. Nevertheless, it is hoped that this paper and the previous versions will provide a good reference set for anyone wanting to improve on the performance and success of their ESP applications. All of the previous papers are referenced below.