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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.

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.

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.

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.

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.

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.

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.

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.

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.

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 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.

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.

The status quo continuous chemical injection systems are labor intensive to manually collect data, interpret that data, and implement changes to the treatment via multiple trips to the well site. This results in higher chemical cost, inefficient use of manpower, greater HSE exposure, and lag time for execution. These issues are intensified on electric submersible pump (ESP) wells where higher flow rates require more chemical usage and failure to monitor the treatment program appropriately can result in costly workovers.

The designs of pressure buildup tests are of equal importance to the analysis of the measured rate, pressure, and time data. Buildup analysis techniques are the focus of many texts, journal articles, and short courses, while discussions of the design of these tests are minimal. Many tests are unsuccessful as a result of poor or little design effort and inadequate instructions concerning field data acquisition An effective design not only maximizes the chances of a successful test, but also eliminates unnecessary testing.

This paper describes a process used to analyze hydraulic fracturing treatment data which leads to the implicit estimation of formation stress profiles. The field example is given for the San Andres formation, where a fracture stimulation was analyzed by history matching the treatment data and a resultant stress profile determined. The stress profile determined was then applied to other surrounding wells which were stimulated, and a consistent match of the treatment data resulted.

Today's society abounds with examples of ethical misbehavior in the areas of politics, business, professional activity and personal life. In the view of some, the situation is approaching epidemic proportions. For years, many societies and associations have developed codes of conduct or rules of ethical behavior to guide their members. Many professional organizations require periodic training in ethics. Texas, as well as other states, now requires exposure to annual ethical education as a condition of continuing registration or certification for professional engineers.

The Petroleum Industry is experiencing an increased awareness and understanding of sucker rod compression. This awareness has evolved during the past twelve years, from initial recognition of rod buckling, to a current desire to quantify (measure) the amount of compression required to initiate rod buckling. Recent attention has focused on true or effective compressive loads in sucker rod strings. Measurement of these loads is being documented (1) and data collection is ongoing with improved technology.

Properly prepared produced water can help eliminate the millions of dollars spent yearly on injection and disposal wells. Large holding tanks and wash tanks are often used as oil separators and water polishers throughout ::he industry. Evaluating the effectiveness of these tanks can be accomplished through the interpretation of a retention study and by reviewing analytical data derived from oil parts per million and millipore filter analyses.

This paper discusses a case history of a hydraulic fracture optimization and evaluation process conducted on four Dean formation wells in the Spraberry Trend Field of Midland County, Texas. The first topic of discussion focuses on the basic steps of the optimization process. This systematic process review will show how the fracture stimulation treatments were designed to provide an optimum economic return based on simulated production results. These designs used reservoir data that was carefully collected by the most up to date technological tools and methods available.

The majority of the workovers at the Mabee San Andres Field are for the removal of calcium sulfate scale. The currently used scale converter treatment is a five step process. This includes the application of a paraffin solvent, scale converter, acid and another scale converter followed by a larger acid treatment. A new scale converter treatment is currently being evaluated. This new method uses a xylene-scale converter emulsion as the scale converter and requires only a two step treatment. The well is first treated with the xylene-scale converter emulsion and is then stimulated with acid.

Various polymers and other thickening agents have been evaluated as gelling agents for hydrochloric acid. These materials were compared on the basis of thickening efficiency, acid stability and residue formation upon spending of the acid. Thickeners tested include xanthan polymers, guar gum, hydroxyethyl cellulose, hydroxyethylcarboxmethyl cellulose, polyacrylamide, polyvinyl alcohol, polyvinylpyrrolidone, acrylamide/sodium-2-acryamido-2-methylpropane sulfonate copolymer, and a cationic surfactant which thickens acid when used at high concentrations.

The Warren Unit, located in Southeastern New Mexico produces oil and gas from primarily the Blinebry, Drinkard and Tubb formations. Over the last eight years, many of the Drinkard and some of the Tubb wells in this unit have been fracture acidized to improve production. The main fluid pumped has been a crosslinked acid gel system introduced to the unit to facilitate better leakoff control and, therefore, provide better penetration of the stimulation fluid. The results of these treatments are evaluated.

This paper discusses case histories of load recovery and production data from wells that were fracture treated with aqueous polymeric fracturing fluids utilizing encapsulated breaker in West. Texas and Southeast New Mexico. The basic fracture treatment, design of these wells and their actual load recovery and production history will be compared to results obtained from offset, wells prior to the introduction of encapsulated breaker.

This paper discusses case histories of load recovery and production data from wells that were fracture treated with aqueous polymeric fracturing fluids utilizing encapsulated breaker in West Texas and Southeast New Mexico. The basic fracture treatment, design of these wells and their actual load recovery and production history will be compared to results obtained from offset, wells prior to the introduction of encapsulated breaker.