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.

This paper presents a discussion of the production history, reservoir performance, and operational problems encountered for the pressure maintenance program in the Strawn Sand Reservoir in the Truby, North (Strawn) Field of Jones County, Texas. Primary energy in the reservoir was supplied by solution gas with a partially effective water drive.

A theoretical basis for pressure transient analysis of gas wells with emphasis on the real gas pseudo pressure approach is outlined. An analysis procedure is developed to analyze wells either injecting or producing predominatly CO2 or enriched gas. This procedure is used to calculate flow capacities and skin factors from pressure transient tests in injection and production wells from two CO2 projects. A computer program is documented which aids in the analysis of gas wells with the real gas pseudo pressure. Finally, example calculations are shown for a CO2 well, an enriched gas well, and an enriched gas well contaminated with CO2 / H2S.

The objective of primary cementing is to support the pipe and achieve a seal so that the desired fluids can be produced from the well. Although a lot of effort is spent in designing for effective fluid displacement in the annulus, displacement in the pipe is frequently overlooked. When fluids are being circulated down the pipe, the balance of forces is not correct for efficient displacement. The heavier fluid is on top, displacing the lighter fluid below it, with buoyant forces causing the heavier fluid to tend to fall through the lighter fluid. Wiper plugs are available to prevent this, but in practice, bottom plugs frequently are not used. When bottom plugs are not used, the cement may bypass the spacer. The cement may then mix with or bypass mud, resulting in poor displacement, leading to poor isolation of various well intervals. Other problems include inter-facial mixing resulting in high permeability cement and exposure of pipe to corrosive fluids, or high displacement pressures due to high viscosity of mixes of incompatible fluids. An investigation of the physics of fluid displacement in pipes was undertaken. The study combines the effects of density and rheology and defines the condition which exists when wiper plugs are not used to separate fluids flowing down the pipe. A computer model provides a qualitative evaluation of the efficiency of the displacement process and indicates the possible instability of the displacement front. Case histories are given which demonstrate the effects of contamination or of one fluid bypassing another and the results of the use of bottom plugs.

A Preventive Maintenance (PM) Program has been established in the southeastern New Mexico portion of Continental Oil Company's production department operation. The PM system has been in operation for 12 months and covers over 2000 separate pieces of major surface equipment. The concept of preventive maintenance is not new in production operations; however, most operating organizations incorporate PM and operations in one organization. The primary disadvantage of this type of setup is the secondary priority PM receives. Day-to-day operating problems normally receive first priority and PM work is done after the "emergencies" are handled. For that reason, Conoco's "PM" organization has been separated from the "operations" organization. Preventive maintenance is the systematic inspection, cleaning, lubrication, and servicing of equipment. The objective of PM is to prevent malfunctions and breakdowns, with the result that all mechanical equipment will work as well and as long as it should with minimum repairs. Operations include those tasks that have to be done to efficiently produce oil and gas wells, to monitor and control oilfield facilities, to answer alarms, and to assure that environmental and safety standards are maintained. An efficient production operation must give equal priority to operational tasks and PM. This paper deals only with the PM for beam pumping equipment. However, the procedures followed in establishing the PM for the beam pumping equipment are essentially the same for all pieces of equipment included in this project.

Our entire economy is sick. The illness is generally diagnosed as over-production or under consumption. The disease has become epidemic in the oil producing industry. Some very drastic curative measures are being advocated. The medicine generally prescribed is hard to take and very expensive. Actually, the causes of the malady cannot be eradicated. Barring unthinkable catastrophe, we can expect low allowable and proration for a number of years. Available cheap foreign crude makes prospects for higher crude prices quite unlikely.

ESP systems are difficult to operate in plumping wells. This is a common operating condition in CO2 floods. A flowing well simulates a no-load or gas locking condition at the surface. The controller then shuts the well down as the underload parameters are exceeded. This repeated cycling is damaging to all components in the system. An integrated control system utilizing a downhole sensor, surface controls and RTU can been utilized to prevent unnecessary shutdowns and premature failures. This system by-passes the underload parameters but limits the motor operating temperature to 200_F. If a gas locking or pump off condition occurs, the motor temperature rises, the system shuts the unit down and then restarts once the temperatures normalize. This application increases production and reduced system failures. This paper will detail the production performance with and without integrated control systems.

It is the purpose of this paper to point out one of the most important factors to be considered in the proper design and correlation between the tubular material and the wellhead assembly as related to the compressive overload of the surface casing.

Many production companies in the Haynesville Shale formation have experienced production tubing problems like corrosion and scaling. They also expect to see liquid loading problems due to the water left after fracturing. Most of the frac jobs in the Haynesville Shale use at least 40,000 bbls of water per stage. The Haynesville Shale is typically 10,000 feet below the surface and about 200 feet thick. The reservoir has a bottom hole pressure of approximately 9000 psi and a bottom hole temperature in the range of 250_

The decrease of cement strength with increased temperature and age was first reported by oil field related researchers in the early 1950's as a result of the growing trend toward deep well completions. This phenomenon is generally known as "Strength retrogression" and has been an increasingly important problem to consider ever since. Several methods have been employed by service companies to counteract strength retrogression and each will be discussed here in detail.

Successful design of primary and remedial cementing procedures in fractured formations requires a precise analysis of down-hole conditions, and careful definition of design objectives. Collection of fracturing pressure data is stressed, and methods for applying this information to cementing design are the primary considerations. Remedial cementing is regarded as the more difficult design, and emphasis is placed on this phase of cementing. The use of controlled water loss cement, packer applications, and placement techniques are considered as a basic part of remedial design. Several unique designs successfully used in Western Permian Basin are included.

The techniques for cementing oil and gas wells vary with geological conditions and requirements of the operator. These techniques have developed through usage and engineering studies. All techniques are based on fundamental chemical and physical considerations. To develop these basic principles, the properties of cement are considered in detail. Modification or control of these properties by use of additives is studied with the individual functions. Special consideration is given with the individual functions. Special consideration is given to more recently developed additives and those used for conditions such as exist in West Texas. Viscosity, density, flow properties, strength, etc. are properties given most consideration. Special consideration is given to the mechanics of placing the cement and equipment necessary. Stage cementing, liner cementing and various remedial techniques are discussed. New techniques are listed. Problems encountered in designing cementing procedures for ultra deep wells currently being drilled in West Texas are discussed. The difficulties encountered in the Permian Basin when converting older fields to secondary recovery are emphasized.

This paper deals with the general principles and applications of gas lift. Various types of gas lift operations are discussed. The mechanical operations of flow valves are explained. Types of installations are analyzed. A detail design technique for the most efficient point of gas injection is outlined. Valve spacing calculations are presented. Flow valve operating pressure design is commented upon. Operational hints to increase efficiency are suggested, the closed rotative gas lift system and the future trend in retrievable gas lift equipment are mentioned. The advantages of gas lift are emphasized.

Automatic control instruments have a great deal in common with economic principles; they deal with supply and demand. Considering that an upset in a process is a change in demand, an automatic controller must be capable of changing the supply to re-establish process balance; therefore, automatic control may be defined as balancing supply against demand over some period of time. The period of time involved in making the supply equal to the demand may vary widely, and is primarily a function of process conditions.