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.

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. A "smart" chemical injection system can make possible real-time decisions at the well site and remotely transmitting data for automatic analysis and reporting. This optimized system will inject chemical on-demand, based on inferred flow characteristics from the ESP motor controller, track on-site chemical inventories, and report through a dynamic web-based monitoring system. While these basic principles are transferrable to any continuous chemical injection system, focus will be on ESP production wells.

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. For example, a design recommendation may be not to conduct the test because the results cannot meet the desired objectives. This paper discusses criteria vital to an effective buildup design to insure the successful measurement of rate and pressure data. Factors which must be considered include: identifying test objectives, establishing the optimal rate and duration of the drawdown period, and determining the length of the shut-in period.

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. This procedure leads to a better estimation of created fracture geometry by matching actual treatment data and provides a basis for design and optimization of future treatments. The method of identifying the distance between major stress variations and the magnitude of the difference in this stress will be discussed. The process involves using a 3-D fracture simulator with multi-layering capability, allowing the distance to stress differences to be identified.

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. This presentation is designed to qualify for one hour of ethical training credit each day presented. Each day will contain different information; up to two hours of ethics training can be earned. Included will be an interactive session with those in the audience participating in discussions of a set of prepared questions and several case histories.

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. This paper will provide a more accurate understanding of the amount of compression required to buckle sucker rods and sinkerbars of various diameters. This will be accomplished by presenting the following; 1. Predictive compressive loads that buckle various diameters and lengths of sucker rods and sinkerbars utilizing Euler loads. 2. Measured compressive loads that are required to buckle various diameter sucker rods and sinkerbars. 3. A comparison of predictive compressive loads to measured compressive loads. Knowledge regarding the amount of rod string compression required to buckle various diameter sucker rods will provide the industry better rod string design guidelines. Use of these guidelines will help identify dangerous compressive rod string loads which initiate rod-tubing contact, provide associated wear, and result in rod and/or tubing failure.

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. The flow characteristics of the tank and the tank's effectiveness in removing oil and solids will aid in determining the type of internal design needed for better equipment utilization. This paper will deal with three ways of modifying water holding tanks and wash tanks economically to provide better water quality. The effective methods used in treating reclaimed oil and solids to provide saleable oil will also be presented.

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. Present economic factors including a best estimate on the time value of money, were also used. A state-of-the-art fracturing simulator combined these parameters to formulate the optimized fracture treatments. These resulting Dean treatments were designed to yield optimum economic value over a targeted time period. The second major discussion will focus on the evaluation of these treatments. This evaluation study will be based upon the actual average production history of these four Dean wells versus the simulated production obtained from the design model. This evaluation comparison clearly shows that actual production to date is very close to the production simulated by the model. The study also reveals that production from this fracture stimulated Dean reservoir can be accurately modeled and, therefore, successfully optimized on an economic value basis. These four optimized Dean wells will also be compared on a production history basis to six previously completed Dean/Wolfcamp wells. The optimized Dean wells are completed only in one relatively small section of the Dean formation. The Dean/Wolfcamp wells are completed over much-larger intervals of the Dean formation and in extensive portions of the Wolfcamp formation. Fracturing stimulation treatments were done in these Dean/Wolfcamp wells but an optimization attempt has not been made. Most of fhe wells were completed with two separate fracture treatments per well. The comparison study of these four Dean and six Dean/Wolfcamp wells shows that the average cumulative production of these two differently completed well types is very similar. Although the cumulative production is similar, this study shows that the four optimized Dean wells are clearly more efficient on a production per perforated foot basis. They are also shallower and were each completed with only one fracturing stimulation treatment. All of these factors indicate that the four optimized Dean wells are providing a better value to date than their six Dean/Wolfcamp predecessors.

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. The xylene-scale converter treatment has been tested in the laboratory and in the field.

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. Of the thickening agents tested, the xanthan polymer showed the greatest overall potential for use as an acid gelling agent. This polymer is an efficient viscosity builder and has good stability in 15% hydrochloric acid at temperatures up to 150_F. Computer model studies, which take into consideration cool-down and gel degradation rate at various stages of acid spending, indicate viscosity is maintained when treating wells that have bottom-hole temperatures up to 220_F. Since the gelled acid retains its viscosity during spending, both reaction rate and fluid leak-off are retarded. Laboratory studies, simulating downhole spending conditions, yield a 3.6-fold increase in spending time for gelled 15% hydrochloric acid (22 cp) as compared to ungelled acid. Well test results are presented that demonstrate the effectiveness of acid fracturing treatments employing hydrochloric acid with xanthan polymer.

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. Included are comparisons of other viscous acid treating fluids, proppant laden fluids, a fluid properties discussion, treatment procedure description and well locations in the unit. Lithology differences are discussed to show the limitations of the crosslinked acid gel system.

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. The case study will focus on 15 oil and gas wells in the Permian basin that were hydraulically fracture treated with proppant, placed using gelled-water-based fracturing fluids containing encapsulated breaker. The encapsulated breaker was used to maximize the clean up and minimize the damage caused by polymer in the proppant, pack of the fracture. Recent studies have documented this damage to be more severe as the polymer concentrates with leak-off of the aqueous component, of the fluid than previously suspected. This damage occurs during both the fracturing and fracture closure processes. Conventional breakers used at, concentration levels needed to degrade this damage would result in fluid viscosity reduction when exposed to time and temperature during pumping operations. This viscosity reduction would result in job failure. Proper fracturing treatment, design combined with the correct utilization of the encapsulated breaker has been very successful in the aspects of fracture treatment operations and post treatment production results.

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. The case study will focus on 15 oil and gas wells in the Permian basin that were hydraulically fracture treated with proppant, placed using gelled-water-based fracturing fluids containing encapsulated breaker. The enca.psulat8ecl breaker was used to maximize the clean up and minimize the damage caused by polymer in the proppant, pack of the fracture. Recent studies have documented this damage to be more severe as the polymer concentrates with leakoff of the aqueous component, of the fluid than previously suspected. This damage occurs during both the fracturing and fracture closure processes. Conventions. breakers used at, concentration levels needed to degrade this damage would result in fluid viscosity reduction when exposed to time and temperature during pumping operations. This viscosity reduction would result in job failure. Proper fracturing treatment, design combined with the correct utilization of the encapsulated breaker has been very successful in the aspects of fracture treatment operations and post treatment. production results.

The purpose of this paper is to show how to evaluate fractured tight gas wells using readily available tools and production data. The paper will primarily deal with the application of coupling conventional analysis, type curve analysis, and a single-phase production simulator to find effective fracture length, fracture conductivity, and reservoir permeability.