This paper compares several different types of production prime movers, their operating costs, and how to cut costs. Examples are given of actual operations in Texas oil production.

Formation evaluation is the process of the application of technology to gain or improve understanding the physical characteristics of subsurface rock formations and the nature and distribution of their contained fluids for the purpose of identifying and developing commercial hydrocarbons. Cores and rotary sidewall cores are prized as actual samples of subsurface rock formations and their contained fluids and the opportunity they represent for direct measurements and observations of rock and fluid properties. Because of their expense, these assets are not commonly available to formation evaluators. Cuttings, however, are an inescapable by-product of every well drilled. Cuttings provide petrophysical information such as mineralogy, texture and pore system characteristics of all penetrated formations, as well as stratigraphic information through their appearance and content. They also provide fluid samples for relative hydrocarbon saturation estimates and geochemical characterization. This information can be broadly applicable in all phases of the petroleum industry: exploration, reservoir management, and drilling and completion. The process of assuring cuttings circulated to the surface are properly located on depth requires completion of a circulation lag check. The data gathered to calculate lag time can be used further to determine a lag time openhole caliper in near real time, and an average openhole diameter profile of a new wellbore can be developed during ongoing drilling using this information. A new evaluation element based on openhole diameter trends, the cavings factor, is proposed to quantify anticipated cuttings sample quality during drilling. If value is placed on acquisition of valid formation evaluation data in general, and cuttings samples in particular, real time remediation is possible through this focused awareness on the developing geometry of a new wellbore. The skills and the interest in cuttings espoused by subsurface formation evaluators in the early history of the oil and gas industry has atrophied. Today, the proliferation of digital data and mathematical models permits calculation and generation of impressive volumes of formation evaluation output without ever examining those broadly and readily available natural earth samples, cuttings, to validate the results. Should a binocular microscope sit next to every computer on the desk of every technical professional in this industry? As exploration and development proceeds into the next century, formation evaluators should focus on what is central to their profession and strive to use cuttings classically and innovatively. As a sample of subsurface rock material and surface-retained fluids, this inescapable asset can be used to reduce risk and uncertainty in prospecting and development operations and maximize the value of formation evaluation in the oil and gas industry.

To obtain meaningful results from Wave Equation analysis of surface dynamometer data, the acquired field data should meet certain minimum requirements. This paper will show the effects of the various parameters on the Down Hole Cards. Various parameters will be examined and their effects shown. Some of the topics covered will be: The Effects of Sampling frequency, Aliasing, Lowpass Filtering, Data Slew Rate, and Skew between Load and Position on Sampled Data. A technique, improving signal to noise ratio and performance by Over Sampling and Decimation will also be covered. It is hoped that this information will be useful in making informed decisions about system data gathering requirements.

The paper will discuss the fundamentals of the Mark II pumping unit and the torque analysis. Comparisons will be made to other types of pumping units to show where this unit will have a reduced torque and additional operational benefits to the operator.

Most work on the casing plunger has highlighted its concept and technology. This paper will show the true economics of applying this technology. This provides the producer a true, accurate measure to determine his decision on this concept

Unlike traditional oilfield biocides, those created using Electro-Chemical Activation (ECA) technology, do not interference with gel breakers, do not increase TDS levels, leave no residual toxic chemicals, are cost competitive and are extremely effective killing bacteria without the microorganisms becoming resistant to the natural biocide solutions. This paper discusses

Using a novel, small sized, flow-through electrolytic module, (FEM), and a cost-effective saline solution, nascent oxidant biocides can be produced for preventing and/or controlling micro-organisms that may plague aqueous polymer solutions in surface or downhole oil or gas well operations. The technology involves the use of electric current applied to the FEM while saline water is flowed through the FEM's two titanium/precious metal alloy tubes divided by a ceramic tube. The two flow streams are electrolyticly charged and produce both anolyte (anode solution), which has oxidizing biocidal properties, and catholyte (cathode solution) with antioxidant cleaning properties. These may be used separately or in conjunction with one another to treat various surface and/or downhole issues relative to the protection of water used for preparing fracturing polymer gels. In addition, those same gels or other polymers that have been injected into reservoirs may have become food for biomass growth, which may in turn impede production, fluid recovery or injection operations. Application of anolyte solution can provide remediation of that condition using relatively small, accurately placed volumes. The system produces solutions that provide optimum concentration levels for the function required and then reverts to safe aqueous saline dilutions. The technology has been employed in Russian oilfields, as well as in water treatment applications in Canada and the U.S.A.

Drilling with coiled tubing had its beginnings in the late 1970s, but did not become economical until the mid 1990s. Three distinct areas of operations, each with different technologies evolved in North America. In Alaska, operators have drilled over 600 multi-lateral, highly deviated holes in the existing vertical wells, through the 4 _ inch tubing. Each year the schedule has accelerated and results are significant in volume and economics. In Alberta Province the use of coiled tubing to drill shallow gas has evolved from a curiosity to a 25% market share. There are currently over 50 "built for purpose" coiled tubing rigs in Canada drilling over 3,000 wells/year and continuing to grow. Only recently has the lower 48 states begun to apply technologies proven in Alaska and Canada, drilling new shallow gas wells and reentry for horizontal laterals. Currently active R&D programs are developing the tools to drill in smaller sizes.

Operating expenses in the Moss Unit were reduced by checking equipment designs and reducing equipment loading where possible. The South Cowden, Moss Unit is located in the South Cowden Field, five miles southwest of Odessa, Texas and is operated by Union Oil Company of California. The water injection began in the Grayburg-San Andres zones in 1961. For the six years from 1980 through 1985 the unit averaged 69 rod pumping wells and 41 injectors. corrosion is considered severe. The gas contains 30,000 PPM H2S and the Truck treating is the method of corrosion control and no significant changes in corrosion control have been made in the last six years.

Disposal of concentrated highly toxic or otherwise obnoxious wastes by deep well injection is not a trivial matter, but one which can be undertaken only after careful planning and intensive study. Prerequisites for this type disposal should include consideration of geological conditions, legal requirements, effluent analysis and compatibility studies, as well as engineering and economic evaluations. The major effort in this paper is to present a close look at the priorities and planning required through an examination of case histories.

The purpose of this paper is to discuss the principle of oil production from deep reservoirs by the gas lift chamber method. This paper will be divided into five principle parts: 1) a section explaining the purpose of the chamber, 2) a discussion of chamber operation and arrangement, 3) a section concerning chamber design, 4) a discussion of results obtained by utilizing chambers for deep lift operations and 5) a summary.

It is the purpose of this paper to study in detail the problems involved in operating an extremely corrosive high pressure gas well and the methods which have been employed to successfully resolve these problems.

Two methods that employ a pumping system operating at 10,000 psi (69 MPa) and 20 to 30 gpm (.08 to .12 m3/min) to penetrate through well casing and radially into the formation up to 10 ft will be described. This is a downhole application of liquid jet cutting technology that is also used in mining, manufacturing, and industrial cleaning. The processes utilize a clean completion fluid, compatible with the formation of interest, to mechanically cut through the well casing and then jet cut or erode a tunnel out into the formation. Depth of penetration depends upon the type of tool used and the type of formation encountered. A description of the equipment, operation procedures and applications will be covered.

Casing design, basic cementing practices, and problems that can occur for deep Delaware Basin wells are presented. Pipe inspection is discussed and recommendations are made as to type and amount of inspection required. Because of extreme depths, many deep wells are terminated or completed shallower than anticipated when unforeseen problems dictate that additional casing strings be set. To overcome this problem, integral joint casing is often installed in a relatively tight hole. This operation presents other problems which are explained. The importance of picking good casing points is stressed and is considered the most important single factor in drilling a deep well. Extremely difficult liner cementing jobs where high pressure gas zones are to be cased are discussed. Gas cutting of fresh cement is one of the more serious problems. Green cement has been circulated off the top of deep liners 24 to 36 hours after placement. Possible answers and proposed solutions for better cement jobs are presented. Loss of circulation in the presence of high pressure gas can be one of the most dangerous and expensive problems in deep drilling. Views are expressed on ways to handle lost circulation. If lost circulation is severe, wireline surveys should be made to determine their zones. In certain cases, casing should be run and cemented without regaining circulation. Reference is made to several deep casing strings cemented without circulation.

General discussion of the problems encountered during the drilling and completion of the world's deepest commercial producer, Wasples-Platter No. 1, located in the Hamon (Ellenberger) Field, Reeves County, Texas. This discussion is followed by a brief resume of changes in operational procedures that have been utilized during the current drilling of the two offset wells in an attempt to reduce the magnitude of the problems of the discovery well.

The problems of deep well pumping are many and varied. The troubles encountered not only vary from area to area, but from field to field in a given area, and even from well to well in a given field. The first problem of pumping a deep well is to design an installation that will reduce either the desired amount of fluid, or the maximum amount of fluid, as the case might be. For a given size pump, the rod stress or hydraulic pressure increases with pump depth and the cost of lifting a barrel of fluid increases accordingly. We normally think of operating a sucker rod at a maximum stress of 30,000 pounds per square inch. The well is frequently equipped with 5 l/2-inch tubing and l-inch rods. An 8200-foot string of 3/4-inch rods suspended in air will stress the top rod to 30,000 pounds per square inch. For the same stress, tapered strings of 7/8- and 3/4-inch, and 1, 7/8 and 3/4-inch can be about 10,000 and 11,000 feet in length, respectively. How is it then possible to pump wells deeper than 10,000 feet? The acceptable life of a rod depends not only on the maximum stress but also on the range of stress. We therefore permit an increase in the allowable stress, but reduce the stress range by using a smaller pump. Desired production is obtained by increasing the stroke length. Forgetting the design for the present, let us assume that we have a well quipped with a sucker rod pump and discuss some of the problems that may occur. The hydraulic long stroke pumping unit and the hydraulic pumping system will be discussed later.

Vertical Turbine Pumps are engineered in three basic elements. Each element must be selected to perform a particular function and operate efficiently with each of the other two elements.

As secondary recovery methods become increasingly important in the economic development of oil reservoirs, knowledge of the reservoir fluids behavior becomes essential to attaining optimum performance. Instruments and techniques have been developed that enable identification of the intervals that are contributing oil and/or water under normal producing conditions. Further, the oil and water may be separately and independently identified, both with respect to limits of producing intervals and respective rates of entry. The instruments and techniques are briefly described and examples presented showing results under different completion and producing conditions.

A Laboratory investigation was conducted to provide data necessary to better predict the behavior of gas Lift plungers. The Laboratory phase of the study was necessary since no data was available on full size commercially available plungers. A test well was instrumented to provide pressure, velocity, and volumetric information during the fall and rise cycle of a variety of commercially available plungers. A data bank representing 132 individual runs has been compiled and behavior of 13 different plunger configurations has been characterized by gas slippage, Liquid fallback, and fall velocity. Performance characteristics of the individual plungers has been incorporated in a modified Foss and Gaul* mathematical model which provides predicted minimum casing pressure in close agreement with actual Laboratory tests. The Laboratory data should provide a basis for improved plunger selection and design. As a second part of the evaluation program, actual field data was collected and the correlations developed for the Laboratory tests were finally adjusted to fit field data. The field data was collected from four field Locations with a variety of operating conditions. The final correlations and equations describing plunger Lift operations have been included in a computer program that can be used for design and analysis of plunger Lift operation.

Vapor-phase water in low-enough concentrations is relatively harmless in a natural-gas gathering and transporting system. It is the liquid-phase water which causes all of the difficulties experienced. The usual trouble caused by liquid water is the formation of gas hydrates; everyone is familiar with the so-called freezing of gas lines and equipment in cold weather. Another trouble which is somewhat more obscure than hydrate formation is internal corrosion of the pipe. Elimination of liquid water from a gas-handling system effectively prevents the formation of hydrates and corrosion. Extensive Laboratory research and field testing have resulted in the development of a new, small, short-cycle, dry-desiccant adsorption unit for gas wellhead applications. A fully automatic, self-contained and skid-mounted unit may be used to dehydrate the gas. No external source of energy, other than the gas stream which is to be dehydrated, nor external cooling medium, such as water or gas, is needed.

Costs to drill and equip deep Delaware Basin gas wells have been significantly reduced in recent years despite inflationary trends. Well planning must be meticulously performed and improvements in drilling or completion techniques implemented with minimum time lag. Each casing setting depth must be considered as to how it relates to total cost and safety. The latest improvements in bits and drilling fluid must be incorporated in well planning. Cementing design must consider limited annuli clearance, high differential pressure, high temperature and pumping time requirements. Rig selection and aggressive on-site supervision is important to minimum cost drilling. Effective formation treatments are designed to open all reserves to the well bore. Improvements in drilling techniques and equipment are expected to continue at a rapid pace.

Plunger Lifts are one of the most cost effective and efficient ways to artificially lift fluid production from gas wells and high gas/liquid ratio oil wells. In operation the plunger travels to the bottom of the well where fluid is picked up by the plunger. The plunger acts like a swab, and is then brought to the surface removing most liquids from the tubing. It will also keep the tubing free from paraffin, salt and or scale build up. Fluid removal prevents loading and keeps the well from dying. With continual removal of all produced liquids, there is less fluid weight on the formation which results in greater gas productivity from the well. The system uses the wells own energy requiring no additional power expense. Plunger lift operating costs on the average are less than 1000 dollars per year and produce most wells to depletion.

The Hydraulic Production Units or bottom hole pumps now being used commercially for producing oil wells may be classified into one of two types. These are the single acting reciprocating unit and the double acting reciprocating unit. This paper discusses various design and operational features of the latter.

Increasing the service life of the sucker rod joint is a continuing goal of both manufacturers and users. Whether or not the goal is reached depends on how well the manufacturer designs and builds the component parts of the joint system and how carefully the user applies it in service. The man who makes the product gets one crack at producing the best engineered joint he can; the man running the sucker rods has recurring opportunities to increase or decrease the joint life by field practice. Included in the latter is control of the well environment to minimize corrosion, the service factor affecting joint life as pointed out in Mr. A. A. Hardy's comments to this Petroleum Short Course last year.1 It will be assumed that sucker rod joints are running in effectively inhibited wells; varying degrees of wishful thinking may be assigned to that premise.

Exploration for natural gas in the Sheep Mountain area, located approximately 28 miles northwest of Walsenburg, Colorado, was begun in early 1972. The first two wells completed produced CO2 instead of natural gas. ARC0 Oil and Gas Company purchased the leases from the original lease holders in 1974 and continued development of the field. The boundaries of the Sheep Mountain Unit were finalized in 1981, and the Unit now consists of approximately 9,000 acres. (See Figure 1.) As a result of this purchase, the Company began making studies and plans on how to produce and deliver the CO2 to various oil fields to be used for enhanced oil recovery (EOR) of the oil remaining in place. It was felt that as much as 25% of the remaining oil in place could be recovered using CO2 for tertiary miscible flooding. The production facilities for CO2 recovery are very similar to those used in the production and recovery of natural gas; therefore, the design and construction of the production facilities were not considered to be a major problem. Since CO2 can be transported by different methods, the Company had to select the most economical method for delivery of the CO2 to the oil fields selected for EOR. Based on the volumes needed for EOR and the production capabilities within the Unit, the Company decided to use a pipeline for the transportation of the 330 MMSCFD that would be produced within the Unit.