Better design, study of operations and planned maintenance of subsurface equipment can often result in reduced lifting cost per barrel of oil. A suggested graphical history of pumping operations will be presented which acts as a graphical records help to readily illustrate problem wells and are also good guides for determining remedial action when necessary. Field cases using the graphical form and results of remedial work will be presented. Normal pulling cost and pump maintenance at various depths will be discussed to emphasize the large sums of depths will be discussed to emphasize the large sums of money that are being spent and the need of monthly systematic well records to determine if operational problems exist.

The "Ultrasonic Cement Analyzer" (UCA) is the name given a new generation device (Fig. 1) that continuously monitors strength development of oil well cement compositions. A single sample of cement slurry is placed in the instrument under pressure and heated to simulate downhole conditions. Measurements of the cement's ultrasonic velocity are started during the fluid state and continue through initial set to any desired point of partial or final strength development. Strength values are continuously computed and displayed until the test is terminated. The result is a complete and precise history of initial set and strength development which can be plotted versus time at any point of interest. The UCA functions with little operator attention aside from start up and shut down. The same information from standard API compressive strength crush tests would require curing a multitude of specimens to preselected test times, with no guarantee that the first test would be short enough or the final test long enough to accurately provide the critical information for the job. Since its introduction some two years ago, the principal advantage of the UCA has been simply to speed collection of reliable compressive strength data. For example, one technician with an eight-chamber UCA can produce more data than eight technicians and 64 separate curing autoclaves. In addition, human error and the opportunity for bias is greatly reduced with the UCA.

In the 1940's neutron logging was commercially developed as an alternate method of determining porosity. The ability to respond to formations behind casing foretold a great future. Unfortunately, however, the same principles which allow a neutron log to predict porosity as a function of the hydrogen index of a formation also produce many undesirable effects. The principles of operation of the compensated neutron log represent the culmination of technology intended to overcome these undesirable effects and to provide a usable tool in the search for petroleum products.

Low-temperature (50F to 100F) wells present a special problem for the application of fracturing technology using current highly viscous water-gels. As the gelling-agent concentration increases, the gel/s require more time to effect a complete breakdown of the gel. This tends to slow turn-around time after treatment and, in some cases, inhibits complete clean-up. Techniques have been developed to circumvent this problem, but they involve lowering the gelling-agent concentration. This has also resulted in lowering the proppant concentration and increasing the pump rate. Several studies have shown the importance of high total prop volumes in good stimulation treatments and the importance of controlling pump rate for good frac height control. Thus, stimulation treatment performance has not been as good as it might have been in higher gelling-agent concentrations; higher propping agent concentrations and lower pump rates could have been used. A new low-temperature breaker for water based gels has been developed that allows the controlled breaking of gelled fluids over a temperature range of 50_F to 100_F. Field results are available to show that this breaker is effective in low temperature wells. A summary of this data will be presented.

The objective of most all waterfloods is to inject water at rates as high as possible without fracturing the formation. Sometimes fractures of limited length are required to reach beyond near wellbore damage of an injection well. However, a fracture that grows to larger distances may drastically affect the volumetric sweep efficiency of a waterflood pattern. As waterflood projects mature, increasingly higher water rates are necessary to maintain oil rates. Increasing water injection rates may exceed the fracture gradient and start or extend a fracture. A pressure falloff test conducted on an injection well provides an estimate of the fracture half-length, but the orientation of the fracture cannot be distinguished. A trial and error procedure is shown to determine the fracture orientation and possible affect on the volumetric sweep efficiency on Levelland area waterfloods by using the fracture half-length from a falloff test and a reservoir simulation program.

Maintaining hole gauge has always been a drilling concern and problem. Historically gauge protection above the bit has been accomplished by using hard metals that offer good wear resistance. There are limitations to this method for actually sustaining a quality gauge hole. Other methods for accomplishing a gauge hole are mechanical devices placed in the drilling assembly, such as reamers. These tools also have limitations in directional applications and hostile environments. This paper will discuss the development of a tool that strategically places Synthetic Diamond Enhanced Inserts to accomplish both hole gauge protection and reaming. The performance of this tool will be economically evaluated with offset data for a direct comparison to the drilling curve and the benefit it derives.

In a well bore, the cement sheath is subjected to pressure changes from various well operations such as changes in the densities of displacement fluids, pressure testing, fracturing, and remedial operations. Failure of cement sheath in annulus due to pressure changes can lead to debonding from the formation or the casing causing microannulus formation, and/or produce cracks in the cement matrix thereby providing flow paths for fluids such as oil, water or gas. Such failures lead to expensive remedial operations in a producing well, or continuous monitoring in an abandoned well. Designing cement slurries which can withstand cyclic pressure changes helps allow for extended periods of trouble free operations. However, experimental techniques to measure failure resistance of set cement in an annulus to pressure changes are not available. This paper presents a method of testing cement compositions using well bore models with pipe-in-pipe configuration in which cement was circulated in the annulus, cured and subjected to cyclic pressure loads by pressuring and depressurizing the inner pipe. The failure of the cement was measured by the flow rates during pressurization and depressurization cycles of a fluid containing a dye through the cement column as a function of applied pressure. The method was applied to several low density cement formulations. The failure mode at the end of the tests was investigated by cutting the models into several segments and inspection of the cement under fluorescent light. Effects of experimental parameters such as temperature at the time of failure testing, annulus pressure, and slurry design were tested. The results and their implications in designing slurries for long term cement performance are discussed.

Several methods of calculating downhole dynamometer cards from surface dynamometer cards have been presented in the literature. Each of the methods requires knowing the viscous damping coefficient. This paper presents a non-iterative method for finding this term. A new method for calculating-a downhole dynamometer card is also presented. This method is faster and more accurate than the fourier analysis and the finite difference method using the second order damped wave equation. In Gibb's patent, two methods of determining the damping coefficient are presented. One is empirically based and the other is an equation that requires knowledge of the pump horsepower. But to calculate the pump horsepower the damping coefficient must be known. Therefore, an iterative procedure is required. This paper presents a non-iterative method for calculating the viscous damping coefficient. An improvement of the method presented by Everitt is suggested and comments on variable damping are made. A coupled set of first order linear differential equations is solved using finite differences to obtain a pump card. A cyclic boundary condition called the wrap around is used to eliminate problems associated with the end points. The wrap around condition eliminates iterating and allows for direct solution.

The vast majority of hydrogen sulfide monitoring systems historically use the solid state, semiconductor, metal oxide film type sensor. This type of H2S sensor has some inherent traits which manifest themselves in the field as application problems. Examples of these application problems include lack of repeatability (span drift), partial or total loss of response with removal of power, frequent and complicated calibration requirements, desensitization with exposure to moisture and the need to subject the sensors to H2S gas between calibrations to prevent them from "going to sleep". The following is an in-depth explanation as to how and why these problems occur along with the hows and whys behind a recommended solution.

Gas passage performance of gas lift valves under dynamic conditions has only been studied in the last twenty years. Proper assessment of gas injection rates at valve operating conditions requires the use of sophisticated measuring and control equipment only a few companies possess; and involves tedious and time-consuming data acquisition procedures. As a result, many gas lift installations are designed even today without properly accounting for the dynamic behavior of operating gas lift valves. The authors applied a novel approach to the description of gas lift valve performance and used Computational Fluid Dynamics (CFD) techniques to determine the valve's gas passage characteristics. CFD calculations provide a numerical solution of the governing equations (like the conservation of mass, energy, etc.) that can be written for a flowing fluid. To facilitate the simultaneous solution of the governing equations the flow space (the inside of the valve available for gas flow) must be divided into sufficiently small final volumes i.e. cells. Since the accuracy of flow modeling greatly depends on the proper setup of these cells the paper fully describes their proper spatial distribution. After the cell structure of the gas lift valve was properly set up, CFD calculations allowed the calculation of the gas volume passed by the valve for different combinations of valve stem travels, injection, and production pressures; i.e. for static conditions. In dynamic conditions, however, valve stem travel is a function of the net opening force developing on the tip of the valve stem. Since this force can be found by integrating the pressure distribution on the valve stem tip, an iterative procedure was developed to describe the valve behavior. The final result of the proposed iterative calculation model is the dynamic performance curve of the gas lift valve i.e. the injected gas rate vs. injection, production, and dome charge pressures. The procedure developed by the authors gives gas injections rates very close to those received from the universally-applied RP

This paper deals with a new method of obtaining injection and producing well permeability profiles. The flow meter and nuclear fluid density tools and their use in analyzing reservoir behavior will be explained. Numerous logs obtained from secondary recovery projects and in producing wells for fracture evaluation and remedial planning will be discussed.

The present energy situation has required the oil industry to evaluate all feasible methods to sustain and increase production in order to keep pace with our energy needs. 'Lost production due to scale deposition has been a major problem in the oil industry and has plugged many a good well while reducing production in most others. Many different scale inhibition techniques exist today and all have varying degrees of success. It is well known that the most effective and least expensive way to protect against scale deposition is during the initial completion of the well before the problem occurs. Most well completions today include hydraulic fracturing operation using an aqueous crosslinked fluid. These fluids, however, do not lend themselves to the use of scale inhibitors due to compatibility problems. This paper discusses the incompatibility of crosslinked gels with scale inhibitors along with experimental results. This paper attempts to solve the incompatibility problem by proposing three models to run scale inhibitors in conjunction with aqueous crosslinked stimulation fluids. The three models proposed are based on computer studies using a "partial pad" approach. All models have been described in detail and the results of the study have been graphically illustrated. The paper also briefly discusses the different types of oilfield scales, their formation, deposition and mechanism of inhibition.

Long open-hole or heavily perforated intervals with stringers of varying porosities and permeability have always been difficult stimulation problems. In the majority of instances treatments have been staged, continuously, with various types of blocking agents. Only after the job was complete, could any down-hole evaluation of the success of the diverting agents be estimated. Obviously, critical information such as the extent of the formation treated per stage, communicated zones, channeling behind the pipe, etc. was unavailable until after the treatment was over.

Carbonate formations have been treated with acid for many years to increase fracture length and conductivity and, thereby, stimulate production. Fracture acidizing of carbonate formations, however, requires consideration of several parameters. One important parameter is the distance acid will penetrate the fracture before completely reacting. This distance is referred to as the acid penetration distance. Other parameters include dynamic fracture geometry and fracture conductivity. Although these three parameters are largely controlled by-formation properties, they can be strongly influenced by the treating fluids used and the techniques employed to place these fluids. Acid penetration distances have been increased to various extents with chemically retarded acids, gelled acids, emulsified acids and acid systems composed of hydrochloric, acetic and/or formic acids. A new chemical retarder has been developed which can be used with emulsified and non-emulsified acids to help increase acid penetration into fractured limestone formations. The unique chemical retarder is chemically and physically adsorbed on the formation where it slows the reaction rate of acid. Besides retarding the acid-limestone reaction effectively, adsorption also appears strong enough to withstand turbulent flow. Although a retarder may greatly increase penetration distance, other parameters, such as fracture conductivity, also have to be considered if the retarder is to be used. For example, during a retarded acid treatment inadequate fracture conductivity may result if fracture cooling causes over retardation of the acid near the wellbore. Placement techniques are in use, however, that could resolve this problem. During treatment, a less retarded acid can be injected before the retarded acid for better conductivity near the wellbore, and the density of preflush can be balanced with the density of partially spent acid for better acid distribution along the fracture face. This paper will discuss the laboratory evaluation of the new retarder's effect on acid penetration distances and reaction times with non-emulsified and emulsified 15% HCl, 20% HCl, 28% HCl and a 7-1/2% HCl-10% formic acid mixture. Also to be discussed, are acid placement techniques used recently in twenty one Mexican wells with the new retarder. Results of these techniques thus far are also listed.

The oil industry customarily has utilized various clay control additives to prevent formation damage caused by the hydration (swelling) or migration of clays. These additives include inorganic metal cations, (e.g. Zr+4, Al+3, Ti+4, et al.) synthetic polyacrylate polymer types, quaternary ammonium salts, and petroleum heavy ends. Clay stabilization using metal cations is accomplished by ion exchange with cations in the clay mineral lattice. These types of clay control agents are limited in application due to their general incompatibility with most polymers used to viscosify completion fluids. This incompatibility is particularly apparent in crosslinked stimulation fluid systems because the metal cations interfere with the crosslinking mechanism of the fluid. Quaternary ammonium salts are also used as clay control agents. They function in approximately the same manner as the metal cations. Synthetic polyacrylate polymers have been used as clay control agents in completion techniques. The polyacrylate function is two-fold. First, the polymer's cationic character under mildly acidic conditions exchanges with lower charged cations located on the clay mineral lattice. Secondly, because this polymer is a long chain molecule (due to molecular weight), it lines the pore wall which insulates the clays involved in the pore channels. Clay damage control through physical isolation of formation clays has been achieved by using petroleum heavy ends, and other similar materials. This method of clay stabilization has shown a degree of effectiveness. A major problem in using this method is due to economics. A number of clay stabilizers have been reported to fuse migrating clays. These systems are used primarily in sand consolidation, hydraulic fracturing and acidizing applications.

Hydrochloric-Hydrofluoric acid mixtures for sandstone acidizing have been the topic of many investigations with respect to optimum hydrofluoric (HF) concentrations necessary for effective treatment. The hydrochloric acid (HCl) concentration needed is only at a concentration necessary to inhibit the formation of calcium fluoride (CaF2), and to provide a conversion media when utilizing ammonium bifluoride for HF production. All indications show that HCl-HF acids in concentration ranges between 3% HCl-0.6% HFto 6% HCl-1.2% HF are in many instances more effective acidizing systems with regard to eliminating the initial damaging effect caused when more conventional HCl-HF treatments are used. These conventional systems tend to chemically and physically dislodge or remove more than they can effectively "clean up", and depend on additional amounts of following acid volume to "eventually" remove these dispersed formation particles, or force them within smaller spaces in the formation. This fives the indication on conventional HCl-HF acids causeing initial "damage", which is followed by restoration of lost permeability, with some improvement, but seldom in proportion to the volumes and concentrations used. Lower concentration HCl-HF acid systems tend to initiate slower and less damaging reactions, thereby "cleaning up" after themselves and offering improved permeability without the initial probable sloughing threat and subsequent "damage" of the higher concentration conventional HCl-HF combinations. Thus an innovation of utilizing weaker HCl systems with intensification via the use of weak HF concentrations has provided an effective means to successfully acidize or acid-frac low permeability sandstone reservoirs.

Based on the drift-flux model, a new mathematical formulation was developed to predict natural separation efficiency. The new model presented in this work considers the effect of the slip velocity in the radial direction, variable neglected in previous simplified models. In addition, a correlation for this effect was obtained by fitting the model to experimental data. Good agreement of this simplified model with the experimental data for not only lower but also for higher gas and liquid flow rates has shown the important effect that the slip velocity in the radial direction has in the prediction of natural separation.

Use of 4-1/2 OD tubular in the completion of deep gas wells makes possible perforating a well with a large, non-expendable type fun while maintaining a pressure differential into the wellbore and treating the well at rates up to 50 BPM. Increases in a well's deliverability as a result of these techniques make the new design economically attractive. These completion methods can be performed on the well without the need to kill it either during or after completion of the well.

Historically, tight gas formations such as the Strawn limestone in Crockett County, Texas and the Devonian in Andrews and Midland Counties, Texas have been treated with pad and acid treatments consisting of gelled water, gelled acid and
crosslinked hydrochloric acid. A new emulsion polymer has been developed which significantly increases the efficiency of these treatments. The new emulsion polymer exhibits a polymer size approximately 15 times smaller than that previously known to the industry. The polymer also utilizes a highly specific external activator to initiate and promote hydration. This process allows the microsized polymer to effectively disperse prior to hydration, thereby dramatically reducing the potential to form un-hydrated masses ("lumps" or "fisheyes"). Both macro and microscopic "lumps" can be particularly detrimental to the formation matrix. This paper will document the increased well production of the &awn formation in Crockett County, Texas and the
Devonian formation in Andrews and Midland Counties, Texas as a result of the polymer's use, outline the treatment, and describe the chemistry of the new emulsion polymer and its operational efficiency and versatility.

One of the primary concerns in completion practices for the Canyon Sand in Sterling, Schleicher, Sutton, and Crockett counties has been to balance possible formation damage with completion costs. The low productivity, and until very recently, the low gas prices for this area has made the use of "exotic" fracturing treatments very difficult to justify. The fluids were normally a gelled water or gelled weak acid system, often used with CO2. In those instances where the treatments are performed via tubing, low injection rates often contributed to screenouts. The recent advent of cross linked water based fluids and more effective clay stabilizers has reduced both the screenout problems and formation damage. Within the last 8-12 months, a complexed weak acid system has been developed which has demonstrated a combination of most of the advantages of the other systems with very few disadvantages. The ability to transport sand out to the drainage boundary is the ideal stimulation practice for almost any "tight" sand. This idealized treatment, though, is often not economically justifiable due to the inefficient nature of the fracture fluid, especially the earlier fluids used in this area. In this paper, we will investigate the theoretical and practical aspects of pumping a complexed weak acid system. This system possesses a large number of the desired characteristics for use in the Canyon Sand -- high viscosity, low friction loss, low pH compatibility with C02, compatibility with clay stabilizers and fluorocarbon surfactants, low fluid loss, and excellent sand transport properties.

A new friction reducer was tested in various fluids to measure its performance in both a small scale flow loop and a field scale system. The polymer was mixed into fresh water and a 1% KCl brine, then pumped through 1_ inch coiled tubing and straight pipe. Drag reduction as high as 69% was achieved in the coiled tubing, and as high as 84% in straight pipe. The study also included 7% KCl, 10 ppg NaCl and 11.4 ppg CaCl2. A small scale flow loop, consisting of _ inch diameter coiled tubing and straight pipe was used. There was good correlation between the fresh water friction pressures measured in the small scale flow loop and full scale system for straight pipe. The measurements using the _ inch coiled tubing over estimated the amount of friction anticipated in the larger coiled tubing. The heavier brines generally required greater polymer loadings.

Fiberglass reinforced pipe (FRP) was originally developed and marketed in the oil field as a highly corrosion-resistant alternative to steel in relatively small-diameter, low-pressure gathering and flow lines. As the acceptance of FRP grew, so did the demand for larger diameters, and higher operating pressures. This acceptance of FRP in the oil field as an almost commodity item inevitably led to widespread stocks of fiberglass at both the distributor and the end-user level, until now probably 70% of the pipe sold is installed without the specific knowledge of the manufacturer.Aside from the educational aspects which are necessary with all new materials, the major reason for this kind of attention was the need to insure that the crews were trained in the proper installation of the adhesive bonded joint. It can be proven that a properly made adhesive joint, under the right conditions, is as strong as the pipe itself and, in fact, these requirements are written just that way in some standards and specifications. Unfortunately, this is more easily specified than it is attained. Most thermosetting adhesives are sensitive to both humidity and temperature conditions. Adhesives, by definition, rely on intimate surface contact in order to perform efficiently, hence the need for nearly perfectly clean and dry bonding surfaces. As anyone who has tried to lay adhesive joint pipe in a West Texas dust storm or a Louisiana "Sun Shower" can tell you, these conditions are not always easily attainable. In addition to all this, because adhesives undergo a chemical reaction, temperature plays a critical role in the working time in the container and in the curing time of the joint. Recognizing these limitations, FRP manufacturers have spent a great deal of time and money working to minimize these difficulties and increase the overall reliability of the joint. For example, nearly all FRP is supplied with end protectors to keep the bonding surfaces clean and dry. Many suppliers offer heat assist methods for curing the joints in cold weather. Installation instructions are supplied with each adhesive kit. At least two of the major manufacturers are offering adhesive joints with a built-in mechanical assist to hold the joint straight and immobile while the adhesive cures - all of this in an effort to improve the reliability and acceptance of FRP throughout the industry.

In an everyday review of well and reservoir performance there is a wealth of interpretive tools such as the one given in SPE Monograph No. 1 on build-up interpretation and in many articles in the SPE journals. Too often, however, the meager data available for analysis causes concern as to the reliability of the conclusions. A typical problem involves the declining production rate of older wells, where the engineer is faced with the problem of determining what remedial steps, if any, can be justified. Several possible problems come to mind. 1. The pump may not be operating efficiently. 2. Scale deposits may be forming in the well, causing skin damage. 3. The reservoir pressure may be lower than expected. 4. The formation may be tighter than expected. This paper describes a new practical service for acoustically determining build-up curves for pumping wells. Included in the service is a rapid standardized analysis that provides the client with measures of pump efficiency, estimates of skin damage, formation permeability and reservoir pressure. Figure 23 shows a summary of the reservoir data obtained in this analysis.

In the recent National Petroleum Council (NPC) report to the Secretary of the Interior on the U.S. Energy Outlook", it is noted that naturally- occurring geothermal steam and hot-water reservoirs in California and Nevada, while potentially contributing up to only two percent of the total U.S. electrical generating capacity by the year 1985, could supply over one-third of the projected electrical power requirements for those two states (16,000 MW out of a total estimated requirement of 52,000 MW). The NPC projection, while close to a recent estimate by Dr. Carel Otte*** of a potential 20,000 MW of neglect any significant contribution from other western states. However, other estimates of the U.S. geothermal potential are considerably greater than those given above. A very recent state-by-state geothermal resource evaluation gives a total U. S. geothermal potential several hundred times greater than the NPC projection. However, this quite realistic evaluation is based on one additional premise not considered in the NPC projection: that a method can be developed for economically recovering the thermal energy contained in the much more numerous reservoirs of hot rock that are nearly impermeable to circulating ground water. One such method is the subject of this paper.

Successful acid stimulation requires a method to distribute the acid between multiple hydrocarbon zones. Since almost all producing wells are inhomogeneous, containing sections of varying permeability, this can be a huge problem. In addition, the water saturation of the various zones plays an important role. Since acid is an aqueous fluid, it will tend to predominantly enter the zones with the highest water saturation. These water zones are also often the highest permeability zones, so acid stimulation will often result in large increases in water production. There can be many negative aspects to increased water production, such as increased lifting and disposal costs, increased corrosion, etc. This paper describes the use of a new low viscosity system which can inherently reduces formation permeability to water with little effect on hydrocarbon permeability, and also diverts acid from high permeability zones to lower permeability zones. This new system has been used in offshore Mexico in the Chuc, Caan and Pol fields among others over the past year. During this time, over 30 wells have been treated with the new system. Most standard acid treatments in this field result in increased hydrocarbon and water production. The new system has resulted in increased hydrocarbon production with no increase in water production, and in some cases a decrease in water production. Details from several of these jobs will be presented showing the diversion and production results.