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.

A gas separator has been developed and successfully field tested in several beam pumped wells which were subject to severe gas interference. The new design is based on several innovations: l Decentralization of the gas separator in the casing, insures that a minimum amount of gas enters the separator. l The presence of two or more ports located on the narrow side of the annulus where the gas separator touches the casing wall. l Sizing the OD of the outer tube of the separator so that it is equal to or greater than the OD of the tubing collars. l The addition of a diverter at the bottom of the separator to direct most of the gas flow towards the wide side of the annulus. These innovations have resulted in a gas separator efficiency much greater than that of conventional designs.

Proper implementation of a successful polymer flood is facilitated if certain engineering requirements are considered. A recommended sequence of events is outlined to describe engineering requirements for a polymer flood. An overview of the feasibility, design, and start-up phases and a more detailed discussion of some aspects follow.

This paper is presented to assist those involved in designing, installing and operating source water pipe line systems to serve waterflood operations. The design and installation of the source water system to supply Capitan reef water, produced in Winkler County, Texas to various waterflood operations in the Ector County area will be discussed in detail to indicate the various problems which are encountered in the design and operation of this type of facility.

A carbon dioxide (CO2) supply well was drilled and completed by Conoco Inc. in the Elsinore Field, Pecos County, Texas in September, 1983. The well was drilled toprovide CO2 for the Ford Geraldine (Delaware Sand) Unit, Reeves and Culberson Counties, Texas. The well tested flowing 11.5 MMCFPD of saturated CO2 at a pressure above the critical. The corrosive nature of the saturated CO2 at a pressure above the critical
necessitated a careful study of pipeline 4 g and dehydration options. Ultimately, the CO2 would have to be dehydrated, since it would be moved to the Ford Geraldine Unit through an existing unprotected steel pipeline. This paper details the design and operation of the Elsinore "73" No. 1 CO2 dehydration facility. Specific topics that will be discussed are pipelining and dehydration alternatives, molecular sieve (mol sieve) bed design, equipment and piping, metallurgy, fuel options, automation, startup and operation.

Accurate hydrocarbon measurement requires equipment and methodologies that enhance out ability to minimize uncertainties. The purpose of this paper is to discuss the advantages of LACT measurement versus tank gauging and to address the carious technologies utilized in determining the quantity and quality of liquid hydrocarbons in custody transfer service. In addition, this presentation will address proper design and operation of such LACT components as recommended by API.

The gas lift system of artificial lift is basically a four component system. The components are designed to fit individual well requirements, but more important is that the design of each component is compatible with the remaining components of the total system. Too often this is overlooked. With a good understanding of the four components, their dependence on each other, their variations as dictated by the well data, and their effect on the total system; the engineer is equipped to design a very efficient lift system. With this same understanding, the operator is equipped to get maximum production from the system with minimum operating expense. The purpose of this paper is to fully describe each component in the light of its effect on the other components, and to keep in mind the efficiency of the total lift system as seen by the designer and operator.

The sucker rod pump is the oldest and still the most widely used means of artificially lifting oil from the well bore. With the demand for higher volumes, from greater depths, with high gas-oil ratios and the use of propping agents in fracturing, the service and performance of the down well pump is greatly impaired. Careful selection of pumps and operating techniques will increase the performance and insure an economical operation.

Ten years age the name "Thermal Recovery" was usually applied to the forward combustion oil recovery process. Today, so many variations of oil reservoir heating methods have been proposed and tested that "Thermal Recovery" now has a far more general meaning. Any oil recovery process which depends upon application of heat to a reservoir is a thermal recovery process. This classification includes: (1) production well heating, (2) both forward and reverse combustion, (3) continuous hot-fluid injection (such as a steam or hot-water injection, (4) intermittent hot fluid injection (such as the push-pull steam injection), (5) use of nuclear devices, (6) electrolinking or electrocarbonization. . . It is the purpose of this paper to summarize sources of design information available for these thermal recovery processes.

The purpose of this paper is to outline and illustrate the calculations required to design a closed rotative gas lift system. Design considerations that are required for continual operation of a closed rotative system without make-up gas after initial charging are discussed. Detailed calculations for a single intermittent well system are offered. These calculations are presented in a step-by-step manner. The effect of expanding the system to include other wells is illustrated.

Ultra-high-slip motors with speed variation capabilities in the range of 45% have been used on beam pumping installations for more than six years. As various producing companies started trying these motors, many improvements in system operation were noted, including: 1. Reduction in peak polished rod load 2. Increase in minimum polished rod load 3. Improved rod life 4. Reduction in peak torque by the API Torque Factor Method 5. A greatly altered dynamometer card shape which showed a tendency to approach the rectangular or parallelogram configuration 6. More production at the same strokes per minute 7. Greatly reduced current (ampere) peaks 8. Greatly reduced RMS (thermal) ampere requirement with a resulting improvement in power factor 9. A much steadier energy (kilowatt) requirement with frequent reductions in total kwh required. 10. Reduced distribution system voltage drop 11. Slower and smoother start-up of the pumping system with a visual recognition that its start-up was less strain on all components of the system 12. A greatly reduced start-up current demand which reduced the possibility of voltage collapse from heavy system loading. These dramatic results created much enthusiasm among those who were involved with the operation and use of the motor. It was assumed by some that all these dramatic results would be obtained on every well in every condition, but that was not the case. On some wells no improvement in dynamometer card shape or rod loading was noted with no apparent improvement in torque loading on the gear box. These tests, which were seemingly failures, caused many interested industry people to doubt the value of an ultra-highslip motor. Some even stated that it had no value or was detrimental to the system. Many heated and enlightening discussions ensued which contributed greatly to the present understanding of the total system operation.

This paper will stress the importance of understanding the various types of corrosion which occur in a well; to do this it is necessary to understand why and under what conditions they occur. Then, the proper cementing composition and procedure can be selected to help prevent the problem from reoccurring.

A 4-ft by 12-ft transparent, vertical fracture model is used to study the prop-carrying abilities of both non- Newtonian and Newtonian fluids. The design parameters and difficulties encountered in building and operating the model are discussed. Solutions to problems such as uniform distribution of prop in the sample area, uniform flow across the sample area, and reduction of end effects are described. A novel technique is used to record and reduce the prop trajectories. Observations of suspended prop flow in vertical fractures are presented.