Stable foam has been used to drill large diameter near-gauge holes at increased penetration rates in low and high temperature formations and in top hole drilling in West Texas. The use of stable foam in conjunction with hydraulic snubbing units and reeled pipe units has been successfully used for a variety of well servicing operations under substantial wellhead pressure. Jobs are completed at less cost than those where killing fluids are used; and formation damage is minimized or eliminated.

Injection of liquid carbon dioxide with treating fluids has been used for many years to improve results and to eliminate some of the problems associated with the stimulation of oil and gas wells. One purpose is to promote faster cleanup without the need of swabbing. When the pressure is released at the wellhead after the treatment, the carbon dioxide vaporizes and forces the treating fluids from the formation. Presence of this gaseous carbon dioxide in these fluids reduces the weight of the fluid column so that normal reservoir drive can then help unload the fluids from the well. Rapid recovery of the stimulation fluids is normal. Under certain conditions, dissolved carbon dioxide and calcium salts can react to form a calcium carbonate precipitate. This paper discusses the conditions of temperature, pressure, and pH under which calcium carbonate does not precipitate.

Until recently, there has not been an effective method for effective proppant fracturing of horizontal wells initially completed using uncemented liners, whether pre-perforated, slotted, or perforated after installation. A new technology that incorporates hydrajetting, fracturing, and simultaneous injection down the treating string and the annulus now allows the operator an opportunity to fracture stimulate such completions, placing separate propped fractures at specific selected locations along the lateral. This process is also applied in wells completed with barefoot openholes as well as cemented liners, but this paper will specifically address its use in non-cemented liner application. In some instances, the hydrajet-fracturing technology has been applied as a last-hope effort to make poor producers into economic completions. After the technology proved successful, operators have been able to continue drilling in areas that were at or near the point of abandoning the drilling program due to ineffective stimulation results.

Crosslinked polyacrylamides have proven themselves to be successful, when properly applied, in shutting off water-producing zones and thief zones in a variety of formations. The same principles that allow polyacrylamides to inhibit water movement effectively in pay zones should also be helpful in controlling fluid movement in a variety of situations such as: 1. Low injection rates of 0.25 to 1.5 BPM 2. Microannulus leaks 3. Casing shoe and liner top leaks 4. Mechanically induced holes or corrosion in casing 5. Potential bridging of solids in commercial squeeze fluids which may result in limited penetration or several attempts before a successful squeeze is achieved 6. Fresh water-sensitive formations requiring controlled pH.

Various types of scales have long been a harassing problem throughout the oil field. Their buildup in the formation as well as along the wellbore decreases production by blocking the flow of oil, either by skin damage in the formation or by plugging off the perforations and lowering pump efficiency. If a tendency for the formation of scale can be predicted, it may save time as well as money in the treatment of that well. The basic types of scale encountered are calcium sulfate (CaSOd), barium sulfate (BaSOd), and calcium carbonate (CaCOq). Their precipitation is mainly due either to the mixing of two different formation waters or the mixing of injected water with formation water, the latter being the more frequent case. Scale is not always found downhole; frequently, it may be found in flowlines, separators and other surface equipment. Scale deposits are usually deposits of inorganic salts that result from the combination of a few parameters. Changes in pressure, temperature and mineral compositions of the waters are the parameters that affect the rate at which scale precipitates. Time is another factor often overlooked; the chemical reactions that produce scale are not spontaneous.

Plunger lift excels at producing high GLR oil wells and removing liquid accumulations from gas wells. As reservoirs deplete and flowing rates decline, the gas phase becomes less efficient at lifting the liquid phase to the surface. Allowed to continue, the flowing gradient will become heavier until the well loads up with liquid and stops flowing. In gas wells, smaller tubing (siphon tube), a compressor, rod pumping, or plunger lift is installed to maintain flowing status. Neither the smaller tubing nor a compressor is a permanent solution. They increase the gas velocity initially so that the liquid will be carried out; however, at some time in the future the gas rate will again fall to an inadequate level and the liquid will not be removed from the well. Rod pumping is a permanent solution but an expensive one. Plunger lift provides a permanent solution like rod pumping, however, and at a lower price than any other method. Another alternative is a subsurface liquid diverter. A comparison of plunger lift and the subsurface liquid diverter will be presented in the section on intermittent gas lift. In oil wells, plunger lift may be installed in lieu of other types of artificial lift when the well stops flowing (if the GLR is high enough) or earlier in an effort to lighten the flowing gradient and increase draw-down. In most cases where plunger lift is applicable it will produce a well at a rate equal to or greater than that obtained by pumping, because a high GLR, while necessary for plunger lift, reduces pump efficiency due to gas interference. Once installed and operating, plunger lift can be expected to produce a well to depletion. As reservoir pressure (and thus maximum available casing pressure) declines, so do the producing rate and the need for a high casing pressure. There are a number of plunger lift wells operating with 70-100 psi casing pressure. There are no absolute maximum producing rates for plunger lift as there are none for flowing wells. The limiting producing rate in both cases is as much dependent upon the inflow performance of the well as it is upon its outflow performance. Thus plunger lift should not be automatically ruled out at high producing rates. If high rates are required, the larger diameter plungers should be considered. Plungers can also be used for paraffin removal and have been used in attempts to decrease GOR. A plunger does make a most efficient and economical paraffin scraper and several have been installed for this purpose alone. The attempts at GOR control are often unsuccessful. When the GOR does decrease, it is not due to decreased gas production, but rather increased oil production without an associated change in gas production. The economy of plunger lift is one of the most appealing factors. The capital and operating costs of other alternatives almost always exceed those of plunger lift. The total cost of installing plunger lift is $1500 to $3000.

Sub-surface plungers are finding a wider acceptance over the last few years. Some operators such as Sell Oil in the Ventura Field in California have gathered considerable data to prove that plungers have a wide range of applications. This paper presents a tabular method of determining the suitability of a well for plunger application, and whether the most efficient plunger lift will require additional gas from an outside source or the production of excess gas from the casing. Tables are developed for tubing sizes of 2-3/8 in. and 2-7/8 in. each to a depth of 12,000 ft. Various downhole and wellhead equipment arrangements are given, with application recommendations for each, depending on well conditions.

This paper discusses the role of power cost in the economics of artificial lift. It is specifically directed to the application of electrical submersible pumps (ESP's). A method for estimating the power required by an ESP is presented along with a computer program to assist in the calculations. This paper is directed toward the Engineers and supervisors whose responsibility include the specification of the type of lift systems to be employed and the sizing and selection of equipment.

This paper presents a method to predict the life of sucker rods. It is based on the standard of maximum and minimum stress on a rod as these stresses describe the fatigue life of the rod. The result is a Constant Life Diagram for the rod (sometimes referred to as a Haigh Diagram). The step wise procedure used to construct the diagram is described as well as contrasting the other possibilities for predicting the life of the rod. The Constant Life Diagram can be constructed from laboratory data, but a more practical diagram can be constructed using field data.

Due to recent trends in hydraulic fracturing with very high proppant concentrations there has been a substantial increase in the frequency of screen outs. The present paper discusses methods of predicting screen outs both during the fracture treatment design stage as well as during the actual performance of the treatment. Different types of screen outs are presented with examples. Reservoir data is used in presenting screen out prevention methods. Procedures to handle screen outs along with several remedies are suggested and the merits of each method are discussed. Lab data on formation and sand pack damage due to mishandling screen outs are also shown.

The petroleum engineer is often required to estimate the pressure production performance of an oil well in order to determine its productive capacity. This paper discusses various methods that have been proposed in the literature for describing individual well performance in solution-gas drive reservoirs. The forms of the oilwell deliverability equations will be presented as well as methods for predicting future performance. An example will be used to illustrate and identify data requirements for each method.

The petroleum engineer is often required to estimate the pressure production performance of an oil well in order to determine its productive capacity. This paper discusses various methods that have been proposed in the literature for describing individual well performance in solution-gas drive reservoirs. The forms of the oilwell deliverability equations will be presented as well as methods for predicting future performance. An example will be used to illustrate and identify data requirements for each method.

Recent developments in stimulation practice have resulted in two or more fluid systems being used continuously during a treatment. Fracture acidizing, for one, has involved the use of a highly efficient pad fluid preceding the acid into the fracture. In the use of the crosslinked gels, it is common practice to precede the gel-sand slurry into the fracture with a pad fluid of an entirely different character. Where these techniques are used, it is useful to know the rate at which one fluid is displacing another and the location of the interface between these two fluids. The importance of this information is as follows: 1. In fracture acidizing, the location of the fluid interface indicates the farthest point that the acid has reached into the fracture. 2. In using the crosslinked gels with proppants, the location of the interface pinpoints the leading edge of sand-laden fluid and hence, propped fracture length. It can also provide valuable information concerning sand scheduling. 3. Where overflush volumes are used behind high strength acid treatments, this information is valuable in sizing the volume to be used as overflush. The gross, averaging techniques used in the past have not allowed the location of the interface between two fluids or stages of the same fluid. In order to develop a method to accurately predict the interface location it was necessary to go back to the basic fluid mechanics of fracturing. In this analysis a greatly simplified expression was developed which predicts fracture area within 10% (or less) of the Howard, Fast, and Carter equation." This simple equation has greatly simplified fracturing and fluid displacement analysis without introducing significant errors in accuracy.

Stanolind Oil and Gas Company (now Pan American Petroleum Corporation introduced their "Hydrafrac" process of well stimulation to the petroleum industry in 1948." In the following year, the first commercial fracturing treatment was conducted, thus introducing the petroleum industry to one of the most outstanding well stimulation practices of the past two decades." Since the initial fracturing treatment was executed in 1949, over 400,000 additional treatments have been performed in the free world, as well as an untold number behind the Iron Curtain." During the past 18 years, many advancements have been made in the concepts of hydraulic fracturing theory concerning the orientation and azimuthal direction of induced fractures. The purpose of this paper is not to clarify these concepts, but to present a sound technique of effectively employing the concepts. Discussion of theory will be confined to only that necessary to clarify the procedures presented in the paper.

Water preflushes have been used for many years to precede acid fracturing treatments. One of the primary functions performed by the preflush is to establish injectivity into the reservoir before acid fills the tubular goods. Preflushes also perform other functions which can contribute to more efficient use of acids and provide greater effectiveness from acid fracturing. This paper discusses the influence of preflushes on acid fracture designs and describes preflush systems which have been used successfully.

This paper includes a description of the dynamometer instrument used, discussion of its application in a typical hydraulic pumping installation, presentation of actual dynamometer cards with pertinent hydraulic pumping data, and interpretation and analysis of actual dynamometer cards considering pump operation and well conditions.

A cooperative study of the Grayburg/San Andres reservoir is being conducted in response to the United States Department of Energy's Class II Oil Program. The purpose of this study is to preserve access to existing wellbores by identifying additional reserves. Production problems associated with shallow shelf carbonate reservoirs are being evaluated by a technical team integrating subsurface geological and engineering data with 3-D seismic data. Engineering analysis, subsurface control from wireline logs, and 3-D seismic data will be integrated using a network of state-of-the-art software on a high performance computer workstation. It is expected that this study will demonstrate a methodology for reservoir characterization and subsequent development of the Grayburg and San Andres reservoirs that is feasible for even small independent operators. The integrated multidisciplinary approach of reservoir evaluation is relevant to many shallow shelf carbonate reservoirs throughout the United States. This paper reports on some of the work performed to date which consists mainly of collecting and appraising large volumes of data. principally well logs. well completion records, and laboratory results of rock and fluid property measurements. Much early well data is missing: this being a field discovered nearly 60 years ago at a time when such extensive reservoir evaluations were not contemplated. This factor is inherent in many fields in the surrounding area that have been successfully waterflooded. With the aid of modern technology, combined with sophisticated geological and engineering analyses, the probability of determining the economic feasibility of waterflooding this acreage should be enhanced.

The current reservoirs declination and depressurization in combination with the continuous reduction of incorporated reserves to the oilfields has challenged the engineer staff to either increase the extraction rate, with a significant increase of the water volumes applied in order to pressurize the field and/or pushing the limits of the artificial lift system (ALS) using biggier pumps and equipment in combination with deeper wells. Despite all the safety factors that have been considered for conventional sucker rod designs, the operating companies understood that the system was reaching its mechanical limit due to frequent and premature failures. After analyzing records, field data basses and statistics we concluded the API sucker rod connection is the weakest link of the system, where around 75% of failures occur. To face this mechanical limitation and to increase the rod pumping efficiency Tenaris developed the premium connection, which overcomes the threshold set by the API connection. Since 2008 to these days this technology was used in different oil fields increasing its performance and making feasible to produce wells with extreme conditions. This paper aim is to show the sum up of the most representative experiences: higher loads, increasing production, reducing failures and extending running life; establishing new parameters in the artificial lift system.

With the aim of developing a more reliable connection to be used in the current artificial lift systems, Tenaris has worked in an innovation process whose outcome was the premium connection product family for sucker rods. This paper explains the comparison between the premium connection design and the API connection design through finite element analysis methods, the product validations full scale tests for beam pumping and progressive cavity pumping, and the application recommendations.

Utilization of computer simulations addressing the placement of chemicals and/or cements for remedial repair workovers has demonstrated valuable assistance in successfully repairing integrity problems. Various situations encountered where casing leaks, isolation failures, and other repairs to wellbores and inter-reservoir communications may be addressed with a variety of solutions. Selection of the right solutions and how to selectively place them into the problem areas have historically needed a method to assist in the control and monitoring during design and in real-time operations. Often complicated situations are approached with highly complex solutions, primarily selected based on diagnostics performed to investigate and define the problems, their sources, their features, and the needed solution attributes and features necessary to satisfy the requirements.Computer simulation performed to address as many conditions and situations have shown to be of great assistance in designing and performing workovers when organized into the operations and performance of actual workovers. Pressure responses used to compare actual to design results enable operators to make decisions and change operations if needed. Details of the techniques used and the demonstration of various cases employing this technology are discussed.

Two similar but somewhat different problems exist in preparing old producing wells to be injection wells and stimulating injection wells currently in use. Recognition of the problems to be solved is of prime importance. A several step procedure may be required once the problem have been defined. A discussion of the problems which may exist and possible solutions for these problems is included.

Beginning January 1, 2002 competitive forces will be introduced into the Texas retail electricity market. The march to a competitive market was set in motion in June 1999 by Governor George Bush signing Texas Senate Bill 7 or SB7 into law. SB7 begins a process of unbundling or separating the utilities" functions into three distinct areas - generation, transmission and distribution and REPs (Retail Electric Providers). SB7 will bring profound changes in the way we purchase power at our homes and in our professional lives. Deregulation will bring choice. This choice brings added responsibility, which lies flatly on the shoulders of you the end user.

New artificial lift technology, Pressure Actuated Chamber Technology, PACT, is proving to be a perfect choice for San Juan Basin producers searching for a more efficient and effective artificial lift method to produce CBM and other shallow, low volume gas wells. PACT has shown remarkable success in replacing both sucker rod pumping systems and swabbing as a gas well deliquification method. The PACT system has no moving parts at the surface, a very small footprint, uses virtually no energy and doesn"t require a pulling unit to install or service. PACT systems operate by applying regulated and timed gas pressure to a series of downhole fluid chambers connected with 1.5" poly tubing in a closed loop system. Gas pressure is applied and exhausted to alternating fluid chambers and wellbore liquid is lifted, chamber by chamber, to the surface. The gas used to lift fluid is taken from the high pressure discharge side of the compressor. The gas that is exhausted from the system goes back into the low pressure suction side of the compressor. This paper will explain how the PACT system operates and examine operational data on several wells before and after their conversion to the PACT system.

Because of sedimentation processes over long geological times, hydrocarbon reservoirs are likely to be multilayered. For practical purposes, in the analyses of pressure and rate transient data the reservoirs are commonly treated as a single-layer model. Petroleum engineers better comprehend the models and analyses of single-layer systems than those of multilayer systems. As long as single-layer analysis yields acceptable results, the engineers tend to use single-layer models in analyzing multilayer data. If the multilayer responses are indistinguishable from the single-layer responses, then the single-layer analysis may be applicable to multilayer data. Our research objectives are to study multilayer responses in pressure or rate transient data, estimate individual layer properties, and investigate the results of single-layer analysis on multilayer data. To achieve our objectives. we have revised and improved an analytical model called "Laysim." We used Laysim synthetic data in our study and limited the study to a radial and homogeneous model with isotropic layer properties and a well at center. The model contains layers with no-flow outer boundaries and a slightly compressible fluid with constant viscosity and compressibility. In this research we used log-log diagnostic plots and semilog Horner plots to characterize multilayer pressure and rate transients, and to distinguish between multilayer and single-layer responses in both drawdown and buildup test data. We identified test types and layer properties that are likely to yield multilayer characteristics. We analyzed mu1tila:qer data using a single-layer model, and provided guidelines in interpreting the analysis results. We quantified layer properties by history matching methods using a simple, three-layer model; proposed a two-step procedure for history matching multilayer data; and provided guidelines in matching the data. The history matching methods are simple ways to estimate layer properties without having to do complicated layer testing and interpretation sequentially. We studied relative rate data that are used to allocate the total flow capacity and storativity obtained from a single-layer analysis to individual layer properties. We found their applicability and restrictions.