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.

Organic inhibitors have been used in many applications but most extensively in the petroleum industry. In general, they may be divided into two groups. One group may be classed as "rust inhibitors" insofar as their primary purpose are to inhibit against attack by oxygen. The other group, as used to prevent corrosion in producing oil and gas wells and in the refinement of oil, are made to be effective in the prevention of attack by acids such as hydrogen sulfide, carbon dioxide, hydrochloric acid, acetic, and propionic acids, and the like.

The removal of polymers utilized in oilfield applications is important to the conductivity and productivity of a well. Unbroken gel residue and dynamically formed filter cake on the formation faces are two forms of damage resulting from drilling, fracturing, gravel packing and workover operations. Monitoring the extent of polymeric damage and its cleanup through removal treatments is best achieved through the analysis of flowback samples. This form of analysis can provide valuable information regarding polymer degradation downhole and be used as a quantitative profile for the amount of treatment load recovered. Flowback samples can be tested before and after treatments to determine the total carbohydrate content, which is a measurement of sugar concentration, in pounds per thousand gallons. Guar, cellulose, starch, xanthan and other polysaccharides used as viscosifling agents are examples of complex sugars. Although high carbohydrate levels are a symptom of damaged wells, it is misleading to conclude that lower carbohydrate content equates to a lesser degree of damage. Other factors, such as bacterial presence, breaker activity and size distribution of polymer fragments, contribute significantly to the results of a flowback analysis. This paper presents an improved method to effectively analyze flowback samples. Laboratory protocols are provided and include tests for carbohydrate content, molecular weight distribution, enzyme/bacteria detection and viscosity measurements. This improved flowback analysis provides a method to evaluate polymer load recovery and to detect any polymer damage downhole. Several field studies are also included to demonstrate this comprehensive analytical procedure and how it supplies a more conclusive posttreatment evaluation.

This paper presents a method of evaluating true load capacity of pumping units. Comparisons of various standard and special geometries will be presented along with application techniques to enable the operator to fully utilize maximum unit capacity.

Port sizes of 5/16 in., 3/8 in., _ in., 11/16 in., and 1 in. were tested from 6000 ft. Different tubing loads were lifted with each port size and each tubing load was lifted with varying gas volume per cycle. The efficiency increased as the port size increased.

In 1973 and 1974, the petroleum industry experienced shortages of many items which formerly had been available at a reasonable cost. Not the least of these items are sucker rods. Prior to 1972, manufacturers were producing several types of rods in rather large quantities. From time to time, these rods were sold at "bargain basement" prices to reduce their inventories. During this same time, prior to 1972, pulling units were available usually on a day's notice, to do well work at competitive rates. Sucker rod failures and replacement of sucker rods were more of a nuisance to operators than a large expense. This pre-1972 atmosphere of plenty no longer prevails. Not only has the price of sucker rods increased 60%, but at times the size and type of rod needed is not available. It is also sometimes days or weeks before pulling units are available to fish, pull or repair sucker rod failures in a well. It has become imperative that a concentrated effort be made to eliminate as many sucker rod failures as possible, not only to reduce the direct expense of repair but also downtime and loss of current income. This paper presents one approach to the problem of trying to minimize sucker rod failures.

The recent development of the Bryant - G- Devonian Field (BGDF) has been a significant success for Texaco in the Permian Basin. The field had been producing about 2.0 MMCFGPD with 100 BPD associated condensate production. Through the application of enhanced reservoir imaging and horizontal drilling technology, production was increased to about 60.0 MMCFGPD and 2600 BCPD with expected recoverable reserves being increased by 300 percent. An additional benefit realized by this program was the increase in loading at the Texaco operated gas plant which processes the liquids from this gas stream. During this ongoing program about 50 horizontal laterals have been drilled, either as re-entries from existing wells or from "grass roots" new wells, some with single laterals and some with multiple laterals. As this was the largest package of deeper (>10,000") horizontal wells Texaco had developed in the Permian Basin, the learning curve was relatively steep and often times bumpy. The discussion to follow will outline some of the progressions followed to bring our drilling practices to their current form.

Presentation of the history and development of gas lift. An interesting coverage of gas lift from the first practical application in 1846 to present day equipment.

In an effort to reduce the emissions of Volatile Organic Compounds (VOCs), EPA has passed several regulations that affect the oil and gas industry in a variety of ways. The resulting regulatory quagmire can be difficult to understand and this can make ensuring compliance challenging. This paper examines the recently passed updates to 40 CFR 60 New Source Performance Standard (NSPS) Subparts J, Ja, KKK, LLL, IIII, JJJJ and the new Subpart OOOO. A regulatory review is provided for each subpart that provides a brief explanation of the subpart, affected facilities, and basic compliance requirements, including monitoring, reporting and recordkeeping (MRR) requirements. Compliance strategies, such as flowcharts and relationship entity tables, will be introduced with appropriate subparts when available.

Coiled tubing (CT) technology is continuing to evolve at a rapid pace due to the improvements in CT units, the CT and associated equipment. CT gives operators an alternative method for doing work traditionally reserved for drilling or workover rigs. The scope of this paper is to supply information on several applications currently expanding the use of CT. These include rig-less CT completions, CT electric line and drilling with coiled tubing

All environmental corrections which affect the determination of formation porosity have been experimentally and/or theoretically determined for a dual - detector thermal neutron porosity tool. Corrections which are a function of tool design have been derived from experimental data in over 100 laboratory test formation environments. These corrections are presented both in analytical form and as charts with the defining data points included. The theoretical bases for other corrections are discussed, and the resulting correction curyes are presented. Field logs run in a variety of borehole and formation conditions are compared with core data to verify the accuracy of the corrections. The effects of trace elements with large thermal neutron capture cross sections have also been quantified.

Important advances in oil-finding logs for cased hole use have been made in recent years. The Neutron Lifetime Log, now ten years old has been successfully demonstrated in California and Texas. It is now feasible to explore for new oil and gas in old wells using these logs, and it is confidently expected that further logging improvements would be made possible by additional research and development, to the point that nearly all types of oil bearing rocks could be identified and their oil content assayed. Since such oil finding methods have long been sought, it is peculiar that the commercial introduction of the Carbon/Oxygen ratio log has met with general apathy and lack of interest on the part of the oil industry. The implications of this lack of interest are discussed. It is suggested that more enthusiastic participation by the oil companies is needed in order to demonstrate to the service companies that the service is in fact beneficial and that further development would be desirable. In the absence of evidence to the contrary, it might be concluded that there is in fact very little interest in exploration for new oil in old wells. At least it is presently obvious that there is no significant program of exploration using cased hole logs, although it may be taken for granted that much new oil and gas could be found by this means. It is suggested that the risks associated with cased hole exploration would be less than conventional exploration operations. In the interest of alleviating the oil shortage, and for conserving overlooked and bypassed oil, a plan for stimulating cased hole exploration with oil finding logs would be beneficial to the public and profitable to the industry.

Plungers have been considered by many operators as short term or intermediate solutions to liquid loading problems in gas wells and gassy oil wells. Data is presented in this paper indicating that some producers have routinely utilized plungers to stabilize production and keep wells producing for years at a nominal cost. Well histories, production decline curves along with cumulative production reports will support the producer's case for utilizing the plunger system for such an extended period of time. Plungers, which are sometimes misapplied and often misunderstood, have been around for a long time. With the new state of the art equipment available and qualified personnel to educate operations people, plungers can be a valuable production system for many wells.