The oil & gas production industry has long used circumferential displacement (CD) for making up sucker rods. This is primarily to assure there is sufficient pre-stress "locked" in the threaded connection to prevent separation and allow the axial loads generated during pumping to be carried by the rod string without connection failures. The CD method also overcomes the problems with using only torque for makeup since torque has been proven to be an inaccurate makeup method mainly due to overcoming the various friction factors. These include: surface finish effects and lubrication effects. This paper provides a partial summary of the original tests conducted by Norris to establish the minimum recommended CD values along with additional testing programs conducted over the past forty years

The API undertook a tremendous job of classifying and identifying the many subsurface pumps available to the industry. As a result of their efforts we now have asset of symbols for the purpose of pump identification. All pumps not covered by this set of symbols are classed as Types of pumps. They, too, are made up of as many API parts as possible to keep down the expense of handling so many different parts by both manufacturer and operator.

The composition, relative abundance, and mode of occurrence of silicate clay minerals in 24 Morrow "perm" plugs from a 24-foot zone (12,935-12,959 Ft .> in the Getty No. 1 State "36" Corn well, Lea County, New Mexico have been characterized by XRD , scanning electron microscopy, and Qv (CEC /ml.P .V. > . The objective of this study has been to define the clay mineralogy of these sands and relate them to reservoir quality.

Pores in sedimentary rocks may be lined or filled with a variety of different clay minerals. These clays can greatly reduce permeability, increase acid or fresh-water sensitivity, totally alter the electric log response, and increase irreducible water saturations. The composition of the clays is of great importance in reservoir management. Different clays have different compositions. und thus will react differently to various drilling and completion fluids. As a result, fluids should be designed for the specific variety of clay present in the pores. Four families of clay minerals exist, and each causes different reservoir problems: (I) kaolinite is primarily responsible for the migration-of-fines problem associated with many reservoirs, (2) smectite can be extremely sensitive to fresh water, (3) illite increases pore tortuosity, and (4) chlorite is very acid sensitive. If well stimulations are designed without a knowledge of the type of clay minerals present in the pores, rapid production declines may occur after treatment. In some instances, the damage is permanent. In other instances, a new, properly designed acid job may result in dramatic increases in flow. Therefore, in designing a mud system, a frac job, or even a Waterflood project, it is vital to know what sort of clays occur in the pores of the reservoir rock.

Historically, montmorillonitic clays have provided the essential rheological and filtration properties of drilling fluids; and because of their versatility, clay muds continue to this day to be used more frequently than any other type of mud. They are, however, inherently high-solids, high-viscosity muds. Even if they are initially formulated to have a low viscosity, their tendency to incorporate shales and clays encountered during drilling causes the viscosity to increase, often to undesirably high values. Unfortunately, the thinners used to combat these high viscosities increase the tendency of the drilled solids to disperse into the system, thereby creating a vicious circle. These high viscosities create handling problems; the concomitant high gel strengths increase the tendency to swab-in gas when pulling out of the hole, and cause pressure surges which may result in loss of circulation when running into the hole. But, worst of all, highviscosity, high-solids muds are slow drilling muds, and consequently increase drilling costs. Clay-free fluids were introduced to overcome these disadvantages. There are many different types but their essential features are that they contain no clay in their initial make-up, none is added during drilling, and they are treated either chemically or mechanically or both to reject virtually all drilled solids at the surface. For this reason, they are sometimes referred to as "closed circuit systems". In order to maximize drilling rate the solids content must be kept very low, and the viscosity no higher than that required to clean the hole. Furthermore, the agents used to provide filter loss properties, increase the viscosity or raise the density are those that will have minimum influence on drilling rate; for example, shear thinning polymers are used to increase viscosity and soluble salts are used to increase density. Further advantages of the polymers are that they provide excellent rheological properties for cleaning the hole at relatively low pump pressure, and that some of them have the property of inhibiting caving shales. True clay-free systems are not as versatile as clay muds and cannot be used in every well. For example, since they use soluble salts for weighting purposes, weights above 11.5 ppg cannot be obtained unless solids are added, which violates the low solids requirement. Similarly, it is difficult to drill through a thick section of montmorillonitic shale and maintain the low solids requirement. Also, the maximum permissible bottomhole temperature is 375_F. This paper describes the principal types of clayfree fluids, the principles under which they operate and the conditions to which each type is best suited.

The Solar Compressor was conceived in response to a growing demand in the Oil and Gas production industry for a safe, reliable, portable, self contained, easy to use supply gas source. Use of compressed air instead of produced gas for controls has several advantages including less wasted sellable gas, elimination of problems from wet gas and condensate, and longer control life. Another added advantage is the elimination of hazardous area creation everywhere methane and/or H2S is used for supply gas

A technique has been developed to chemically clean used submersible pumps and flush used submersible motors without the expense of tearing down the equipment and rebuilding it. After the cleaning process, the pump is tested and its performance is plotted against the manufacturer's catalog curve. Over 70% of the pumps put through this process have been rerun without being rebuilt for a substantial savings to the operator. This paper will discuss the process used in cleaning and inspecting the pump and motor. The pump test bench will be described along with the metering accuracy and calibration techniques. The test techniques used on the motor to determine if it should be rerun will be described. Use of the actual pump curve for improving production will be covered, along with statistical data on over 2000 new and used pumps tested in the Permian Basin and on the West Coast.

Closed Power Hydraulic Pumping Systems, introduced in 1950, have been applied almost exclusively to the town-lot and off-shore island-platform operations. The ability of the "closed system" to minimize the size of power fluid treating systems is particularly advantageous where space limitations exist. This presentation will attempt to focus on the other features of the closed power fluid application, particularly those applicable to today's pumping requirements. Of particular interest are production requirements involving: 1- High water cuts from natural or artificial floods; 2- Hard to clean crudes; 3- Dual or multiple zone pumping; 4-Use of fluids other than produced crude as power fluid.

Power oil for hydraulic pumping systems must be clean. In some instances it is difficult and costly to clean up the crude oil. A closed power oil system offers a means of maintaining high quality power oil, because the power oil does not come into contact with produced fluid. This paper discusses various types of closed power oil systems, the conditions where the closed power oil system will most likely have an advantage over the open system, and compares the costs of the open vs. the closed power oil systems.

A study of Denver Unit, Wasson (San Andres) Field, waterflood lift requirements for both current and future lift requirements, was completed in December 1966. This study indicated that for lift capacities exceeding 400 BPD a capital cost saving of $1000 to $2000 per well over bean; pumping could be realized by utilizing a closed hydraulic free-pump system. Available data also indicated that $100 per month per well savings in operating costs could be expected with hydraulic pumping. A closed system is more economical due to the expense required to expand treating facilities to handle the power fluid in an open system. In view of the possible economic advantages of hydraulic pumping, a 2-well Closed Power Water (CPW) and a 4-well Closed Power Oil (CPO) pilot project were installed and put into operation in June 1967. The CPW system was justified from the fire safety standpoint since many unit wells are located in inhabited areas. Major points covered in this paper are installation and operation of equipment, operating problems, and costs for both systems.

This paper contains a discussion, with examples, on how one type-of casing inspection survey is used to identify the depth and circumferential extent of casing corrosion. Corrosion results from one or more of a family of electrochemical processes. Some of these electrochemical processes will be generally described in the later topics. The Dresser Atlas casing inspection log and casing evaluation logs (for the detection of corrosion) provide such information as: 1. Whether the corrosion is external or internal. 2. The degree to which the pipe's wall thickness is reduced by the corrosion. 3. The circumferential extent of the corrosion. 4. Whether corrosion is general or isolated. 5. Basis for monitoring corrosion and effectiveness of cathodic protection of chemical treatment. Corrosion is an electrochemical process that involves chemical reactions and the flow of electricity. Corrosion requires an anode, a cathode and an electrically conductive path between the anode and cathode. In the west Texas-New Mexico area there are many zones with differing electrical potentials with which the casing forms the electrical coupling. These conditions represent the prime cause of external corrosion. With the addition of CO2 inside the casing internal problems as CO, + water = corrosion can be expected. This paper will show a way, though the use of Vertilog, to monitor corrosion activity and assist in evaluating the techniques to combat such problems.

This paper discusses a general review of safety hazards and regulations associated with CO2 injection, work on H2S contaminated
leases, and liability and court litigation concerning oilfield injuries. The safety regulations to be discussed are a compilation of various applicable International, Federal, and State regulations, recommended practices by various petroleum related associations, and interpretations of these regulations as evident through recent court litigation. Though high pressure CO2 injection safety, along with H2S safety, will be stressed, general lease safety recommendations will be made to help reduce operator liability risk.

CO2 Flooding for EOR is in its infancy.

This paper discusses field facilities problems that were experienced during the initial construction and during the actual operations over the last two years. Furthermore, design and operational considerations and changes which have been made will be discussed for future CO, projects. For the purpose of this paper, four areas of the CO, project facilities will be discussed: the CO, injection facilities, the field production facilities, the gas collection facilities, and the excess water handling facilities.

Once it was decided in 1984 to inject CO2 in the Willard Unit (part of the Wasson Field at Denver City in West Texas), determination had to be made whether to automate the project and, if so, to what extent. Why the decision was made to fully automate the project and detailed descriptions of the automation system are the subjects of this paper.

The increasing use of CO2 in varied oilfield applications generates the need for a thorough knowledge of CO2 properties. These properties are responsible for the way CO2 must be handled in order to use it safely and effectively. The chemical and physical properties will be discussed for CO2 alone and in combination with other liquids and the mixtures subsequent affects on equipment. These characteristics and effects can cause numerous safety problems. Safety procedures to be discussed include logistics, maintaining breathable air quality, and several aspects of metal integrity.

With the advent of numerous CO, injection projects, the need has arisen for processing variable composition gases containing over 90% COz. Traditional gas sweetening plants were geared for removal of small amounts of CO2 (and H2S) from natural gas streams. Enhanced oil recovery projects require gas processing plants to remove methane, H,S and NGL's from CO2 laden gas to produce purified CO2 for reinjection.
Of paramount importance is the efficient recovery of the ethane and heavier NGL's, as they represent a key revenue stream for project viability. Enhancement of the NGL content of the produced gas by crude stripping is recognized in pilot and actual projects. Design of process facilities to economically recover the NGL's and purify the CO2 represents an interesting challenge for the gas processing industry.

Iron sulfide scale had caused a number of short runs in producing wells in this West Texas waterflood. A team of producing company engineers, operations personnel, chemical company technicians, and submersible pump company personnel was formed to identify the problem and research methods to correct the situation. This paper presents a history of the field, problems encountered, characteristics such as loss of production that indicate downhole pump problems, and amp chart review. Chemical analysis of the produced water, along with scaling tendencies, were monitored. Metallurgical analysis of the pump parts exposed to the water, and detailed equipment teardown analysis helped identify the root cause problem. Once identified, steps were taken to reduce abrasive wear by coating pump stages to forestall the problem.

Coefficients of isothermal oil compressibility are usually obtained from reservoir fluid analysis. Reservoir fluid analysis is an expensive and time consuming operation that is not always available when the volumetric properties of reservoir fluids are needed. For this reason correlations have been developed and are being developed for predicting fluid properties including the coefficient of isothermal oil compressibility. This study developed a mathematical model for predicting the coefficient of isothermal oil compressibility based on Peng-Robinson Equation of State (PR EOS). A computer program was developed to predict the coefficient of isothermal compressibility using the developed model. The predicted coefficient of isothermal oil compressibility closely matches the experimentally derived coefficient of isothermal compressibility.

CO2 floods impose a number of artificial lift challenges to an operator. Typically as a flood matures, a significant number of the producers are affected by the (X&-water injection cycle. Producers swing through a broad range of producing characteristics. It is not unusual, depending on the injection cycle, for a producer to load up during the water cycle and then flow strongly during the CO2 injection cycle. These wide swings cause troublesome failures, a loss in production and lead to higher operating cost. Since late1995,Alhna Energy has been testing two CO2 gas lift installations in the Denver Unit San Andres CO2 flood. Results have been mixed. One of the two has been converted to a flowing well. The other remains in operation This paper presents an overview of CQ gas lift candidate selection, equipment and selection and performance results of the CQ2 gas lift test.

Coiled tubing fracturing has been widely used as a method of stimulation for the coal seam on the Vermejo Park Ranch. The purpose of this paper is to compare associated cost, production results, and differences in methodology between coiled tubing fracturing and conventional fracturing. The comparisons will be drawn between a sampling of 90 wells completed on two different areas of the field. Past stimulation (conventional fracturing) was done with stage work pumping down casing. This would affect 3 to 9 stages per well during pumping. Current stimulation being done on the Vermejo and Raton coal seams utilize coiled tubing (coiled tubing fracturing). The CT fracturing process increased the number of stimulation stages to 4 to 18 per well. This allows for a more accurate placement of proppant and a more effective stimulation of the producing zones in the well.

Coiled Tubing has been used in oil and gas operations for many years, and has proven to be a very efficient, reliable, and economic tool. The coiled tubing technology has been utilized for drilling, completions, workover, stimulation, and plugging & abandonment work for decades, with considerable success. Coiled tubing for use in artificial lift operations has been somewhat limited, but in the economic environment existing today, new opportunities have been recognized. This paper is focused on three main segments: CT-Lift in normal, rod-pumped wells where sand and scale may be problematic; CT-Lift in monobore wells or where damaged casing may preclude other options; and CT-Lift in gas
well deliquification, where the coiled tubing essentially provides lift options both as a velocity string and as a reciprocating pump string to lift liquids which accumulate at the bottom of a well.

Spraberry operators in West Texas have been fighting casing leaks caused by the corrosive fluids in the San Andres formation for years. Water produced by the Dean, Upper and Lower Spraberry formations is disposed of into the San Andres. There are possibly thousands of Spraberry wells that were drilled and completed without getting cement across the San Andres. This has resulted in plugging many of these wells. Spraberry wells will produce 5 -10 BOPD for decades, but when the corrosive waters from the San Andres cause casing leaks, it becomes uneconomical to continue producing these wells. This paper will discuss the combination of slimhole conversion and the installation of a coiled tubing rod string system to solve the casing corrosion problems in wells that are usually considered P&A candidates. The development of the coiled tubing rod string system will be looked at. Case histories will also be presented.

In the early years of emulsion treating in the oil field, heat and settling were the only major factors employed. Large open pits frequently provided the settling time and the sun contributed some heat. "Sunning" was a common practice. Some producers employed crude-oil fired retorts and stills to reduce the water content of crude. Large boilers were frequently used to heat tanks of emulsion to facilitate settling of water and emulsion. The large amounts of unresolved emulsion from such operations were usually burned as a means of disposal. With the advent of chemical and electrical treatment, the above procedures were gradually replaced. The use of some heat has continued to the present day but treating temperatures have gradually been reduced with many treating plants operating at ambient temperature. Required settling time has also been drastically reduced over the years. For the most part, the energy required to heat crude as part of the treating process, has been supplied by products produced on the lease so has not been recognized as an expense. Losses in crude gravity and volume, sustained as a result of heating, were judged to be insignificant and difficult to measure and had little or no impact on the value or volume of product sold. In past years, heat may have been a low cost factor in treating. Today, with the shortage of fuel and its increased cost, the economics of the use of heat is worth reevaluating. Before assessing the possibility of reducing heat in oil treating, however, a review of emulsification and oil treating is in order to better understand the role of heat.

Use of Coiled Tubing in underbalanced acid washing is becoming more prevalent in carbonate wells with H2S production. Corrosion testing under pressures and temperatures representing downhole conditions is used to qualify a corrosion inhibitor loading. Sour conditions warrant testing with differing amounts of H2S in the gas phase. Safety factors, weight loss and pitting guidelines are employed in the inhibitor design to ensure continued integrity of Coiled Tubing. The thin wall of these tubulars makes corrosion control of the utmost importance. Evaluations of Coiled Tubing after acid treatments examines the surfaces for defects and uses the perlite layer at the concentric center of the tubing wall to determine material losses. Comparisons of laboratory tests to effects on Coiled Tubing, used to treat wells producing from 0 to 60% H2S at temperatures of 75_ to 110_C (167_ to 230_F) are presented. Specifically material deterioration and surface evaluations are compared.