Emulsions in oil production are accepted today as a normal operational condition. The equipment and materials necessary to resolve produced emulsions are usually placed in the field as soon as a well begins to produce water in the form of an emulsion in quantities that exceed pipeline specifications. During the early years of the oil industry neither the knowledge, equipment, nor chemicals were available to treat oil effectively. Early methods of breaking emulsions consisted of settling time, and, in some cases, the use of heat. As a result, emulsion was often drawn off the bottom of tanks and burned as waste.

When Colonel Drake drilled the first oil well in this country he was extremely fortunate in two ways; one, he discovered at a very shallow depth, as compared with present day footages; two, the oil he discovered was a paraffinic, golden colored crude which contained very few impurities. It was easily refined with simple equipment, and required no treatment in the field. The development of problems and their solutions, which are connected with the production of oil, have been gradual.

Paraffin deposition during the production and transportation of hydrocarbons prior to refining represents a very real and costly problem. New inroads for chemical treatment have been made during the past few years. These developments have led to a program of preventive chemical treatments which offers a viable alternative to hot oiling or other mechanical remedies for paraffin control. This paper discusses the design of a paraffin treating program using a batch method of application. Topics investigated are sample identification and characterization, paraffin compound testing, program design, chemical application, field performance evaluation, and program adjustments. These topics are presented for practical application.

A basic discussion of an electrical-chemical dehydration process for breaking oil-water emulsions by passing these emulsions through an electric field.

Choice of plunger type may be as critical as the surface equipment to optimize a plunger lift well. When considering plunger lift candidate's decline, IPR, velocity, fluid and pressure are used to build a proper evaluation. The necessity for proper plunger lift choice in completely optimizing a plunger well can result in incremental production from an existing plunger system by as much as 500 Mcf/day by changing from a conventional plunger lift system to a high speed bypass plunger. However, a bypass plunger in a well with the wrong conditions will not result in a successful increase and may in fact hurt production. In order to properly evaluate wells it is necessary to consider the velocity and the fluid rates for high speed bypass then change to consider more conventional methods. This paper will discuss the well evaluation process as it pertains to plunger lift applications.

Many papers have been written concerning the planning and design of fracturing treatments. Most have involved proposed production increases, fracture conductivity, fluid coefficient and fracture area. This paper will delve into the simple mathematics of cost of fracturing fluids. A total cost comparison of water versus oil based on the general treatment of each fluid, horsepower requirements at equal rates, and fracture area per dollar are presented. Lease crude, refined oil, commercial brine, fresh water and a 40-60 mixture of brine and freshwater will be considered.

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.