Scale has been a major problem in producing wells practically as long as water has been produced along with oil and gas. At the present time, thousands of wells in the Permian Basin are being treated to combat this scale problem. The purpose of this paper is to acquaint the field operating personnel with some of the reasons why scale is formed, the chemicals which have been used in the past for scale treatment, and the chemicals which have been recently developed. Also, a good portion of the discussion is devoted to the results of the use of these newly developed chemicals. Because of the limitation of time, this paper does not include remedial type treatments such as acid treatment of carbonate scale, or acid and certain additives for treatment of sulfate scales. Possibly this subject can be covered at a later date.

Corrosive effect of chemicals on steel was the primary reason the oil industry began searching for an alternative material for sucker rods. This study is not a comprehensive study of chemical corrosion inhibitors, but it will discuss chemical corrosion and its effects on steel sucker rods and fiberglass sucker rods. Steel sucker rod replacement due to corrosion is one of the major costs of oil production. The author will show that water/C02 and sour (H2S) gas has no obvious detrimental effect on a fiberglass rod body.

Environmental stewardship involves not only responsible use of chemicals and materials during drilling and completions, but also includes a thorough understanding potential health and environmental hazard posed by chemicals used in these processes. Recent focus on potential hazards associated with chemicals used in oil and gas production has expanded to include not only chemicals used in treatments such as hydraulic fracturing, but to other applications including cementing and drill fluids. Global focus on chemical disclosure and increased attention on chemicals covered by trade secret protection is driving the industry to assess products used in production processes and consider viable alternatives to address public and regulatory concerns while encouraging products innovation to reduce environmental or human risk. A comprehensive review of products and their components using a scientifically based methodology is fundamental to the identification of potentially unacceptable hazards and can support efforts in product reformulation, where applicable, to produce an efficient and compatible product that may pose fewer or less severe health and environmental hazards.
This paper discusses the aspects of a Chemical Evaluation Process Review (CEPR) that examines products on a component level for various environmental and health hazards in accordance to regulatory standards on a global scale by considering: the presence/absence of specified substances; the likelihood of a product passing a comprehensive OSPAR screen; screening of substances for regulatory lists globally; and a detailed review of environmental, toxicological and physical hazards. In addition this paper will present expansion of the CEPR beyond hydraulic fracturing products as well as acceptance by the industry of environmentally preferred alternative products.

Interest in reservoir stimulation by chemical explosive fracturing is gaining momentum in the petroleum and natural gas industry. This paper discusses the present "state-of-the-art" of explosive fracturing. Characteristics of the three types of explosive products, solid, liquid, and slurry and their specific application to formation fracturing are reported. Explosive loading, displacement, and initiation techniques presently employed in the field are included. Test results from more than 30 field applications using the various explosive products will be reviewed. Field tests to date have been conducted at depths ranging from 40 ft to 7000 ft, using explosive quantities from less than 100 lb to 35,000 lb. Finally, engineering criteria to be used in selecting a well candidate and designing a field application will be discussed.

A chemical gel has been developed to plug leaks in injection wells to provide effective zone isolation and casing protection. Since it is a gel material, the sealant can easily be removed from the casing-tubing annulus for workover operations. This chemical forms a thick gel after placement in seal casing leaks, (2) protect fresh water aquifers from the annulus which helps (1) steel casing from corrosion, and (4) can be removed from contamination, (3) protect the casing-tubing annulus by rotating and reciprocating the tubing and washing out. Chemicals used in this process are nontoxic and are compatible with fresh water aquifers. Field case histories are presented to show operational procedures and injection pressures before and after treatment and to illustrate effectiveness of the treatment.

As with all EOR techniques, the injection of carbon dioxide into oil bearing reservoirs causes fundamental changes in the chemical and thermodynamic properties of the reservoir fluids, not only as they exist in the reservoir, but also as they are produced. Additionally, because of the dynamic nature of CO2 flooding, the produced fluids (gas, oil and water) will change continually as various areas are swept and produced. Thus, producing wells, satellites and production batteries will experience constantly changing fluid conditions throughout the life of the project. Although various portions of the production system can approximate equilibrium, change is inevitable. Given these conditions, chemical programs used in production operations must be designed with flexibility in mind. Chemical treatments must accommodate
produced fluids whose tendencies to deposit scale, corrode steel, deposit paraffin and form emulsions are changing. This paper will address changes that must be made to transform traditional production chemical programs into systems that can maintain the efficient production in CO2 enhanced recovery.

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.