This paper presents a discussion of the production history, reservoir performance, and operational problems encountered for the pressure maintenance program in the Strawn Sand Reservoir in the Truby, North (Strawn) Field of Jones County, Texas. Primary energy in the reservoir was supplied by solution gas with a partially effective water drive.

A theoretical basis for pressure transient analysis of gas wells with emphasis on the real gas pseudo pressure approach is outlined. An analysis procedure is developed to analyze wells either injecting or producing predominatly CO2 or enriched gas. This procedure is used to calculate flow capacities and skin factors from pressure transient tests in injection and production wells from two CO2 projects. A computer program is documented which aids in the analysis of gas wells with the real gas pseudo pressure. Finally, example calculations are shown for a CO2 well, an enriched gas well, and an enriched gas well contaminated with CO2 / H2S.

The objective of primary cementing is to support the pipe and achieve a seal so that the desired fluids can be produced from the well. Although a lot of effort is spent in designing for effective fluid displacement in the annulus, displacement in the pipe is frequently overlooked. When fluids are being circulated down the pipe, the balance of forces is not correct for efficient displacement. The heavier fluid is on top, displacing the lighter fluid below it, with buoyant forces causing the heavier fluid to tend to fall through the lighter fluid. Wiper plugs are available to prevent this, but in practice, bottom plugs frequently are not used. When bottom plugs are not used, the cement may bypass the spacer. The cement may then mix with or bypass mud, resulting in poor displacement, leading to poor isolation of various well intervals. Other problems include inter-facial mixing resulting in high permeability cement and exposure of pipe to corrosive fluids, or high displacement pressures due to high viscosity of mixes of incompatible fluids. An investigation of the physics of fluid displacement in pipes was undertaken. The study combines the effects of density and rheology and defines the condition which exists when wiper plugs are not used to separate fluids flowing down the pipe. A computer model provides a qualitative evaluation of the efficiency of the displacement process and indicates the possible instability of the displacement front. Case histories are given which demonstrate the effects of contamination or of one fluid bypassing another and the results of the use of bottom plugs.

A Preventive Maintenance (PM) Program has been established in the southeastern New Mexico portion of Continental Oil Company's production department operation. The PM system has been in operation for 12 months and covers over 2000 separate pieces of major surface equipment. The concept of preventive maintenance is not new in production operations; however, most operating organizations incorporate PM and operations in one organization. The primary disadvantage of this type of setup is the secondary priority PM receives. Day-to-day operating problems normally receive first priority and PM work is done after the "emergencies" are handled. For that reason, Conoco's "PM" organization has been separated from the "operations" organization. Preventive maintenance is the systematic inspection, cleaning, lubrication, and servicing of equipment. The objective of PM is to prevent malfunctions and breakdowns, with the result that all mechanical equipment will work as well and as long as it should with minimum repairs. Operations include those tasks that have to be done to efficiently produce oil and gas wells, to monitor and control oilfield facilities, to answer alarms, and to assure that environmental and safety standards are maintained. An efficient production operation must give equal priority to operational tasks and PM. This paper deals only with the PM for beam pumping equipment. However, the procedures followed in establishing the PM for the beam pumping equipment are essentially the same for all pieces of equipment included in this project.

Our entire economy is sick. The illness is generally diagnosed as over-production or under consumption. The disease has become epidemic in the oil producing industry. Some very drastic curative measures are being advocated. The medicine generally prescribed is hard to take and very expensive. Actually, the causes of the malady cannot be eradicated. Barring unthinkable catastrophe, we can expect low allowable and proration for a number of years. Available cheap foreign crude makes prospects for higher crude prices quite unlikely.

ESP systems are difficult to operate in plumping wells. This is a common operating condition in CO2 floods. A flowing well simulates a no-load or gas locking condition at the surface. The controller then shuts the well down as the underload parameters are exceeded. This repeated cycling is damaging to all components in the system. An integrated control system utilizing a downhole sensor, surface controls and RTU can been utilized to prevent unnecessary shutdowns and premature failures. This system by-passes the underload parameters but limits the motor operating temperature to 200_F. If a gas locking or pump off condition occurs, the motor temperature rises, the system shuts the unit down and then restarts once the temperatures normalize. This application increases production and reduced system failures. This paper will detail the production performance with and without integrated control systems.

It is the purpose of this paper to point out one of the most important factors to be considered in the proper design and correlation between the tubular material and the wellhead assembly as related to the compressive overload of the surface casing.

Many production companies in the Haynesville Shale formation have experienced production tubing problems like corrosion and scaling. They also expect to see liquid loading problems due to the water left after fracturing. Most of the frac jobs in the Haynesville Shale use at least 40,000 bbls of water per stage. The Haynesville Shale is typically 10,000 feet below the surface and about 200 feet thick. The reservoir has a bottom hole pressure of approximately 9000 psi and a bottom hole temperature in the range of 250_

The decrease of cement strength with increased temperature and age was first reported by oil field related researchers in the early 1950's as a result of the growing trend toward deep well completions. This phenomenon is generally known as "Strength retrogression" and has been an increasingly important problem to consider ever since. Several methods have been employed by service companies to counteract strength retrogression and each will be discussed here in detail.

Successful design of primary and remedial cementing procedures in fractured formations requires a precise analysis of down-hole conditions, and careful definition of design objectives. Collection of fracturing pressure data is stressed, and methods for applying this information to cementing design are the primary considerations. Remedial cementing is regarded as the more difficult design, and emphasis is placed on this phase of cementing. The use of controlled water loss cement, packer applications, and placement techniques are considered as a basic part of remedial design. Several unique designs successfully used in Western Permian Basin are included.

The techniques for cementing oil and gas wells vary with geological conditions and requirements of the operator. These techniques have developed through usage and engineering studies. All techniques are based on fundamental chemical and physical considerations. To develop these basic principles, the properties of cement are considered in detail. Modification or control of these properties by use of additives is studied with the individual functions. Special consideration is given with the individual functions. Special consideration is given to more recently developed additives and those used for conditions such as exist in West Texas. Viscosity, density, flow properties, strength, etc. are properties given most consideration. Special consideration is given to the mechanics of placing the cement and equipment necessary. Stage cementing, liner cementing and various remedial techniques are discussed. New techniques are listed. Problems encountered in designing cementing procedures for ultra deep wells currently being drilled in West Texas are discussed. The difficulties encountered in the Permian Basin when converting older fields to secondary recovery are emphasized.

This paper deals with the general principles and applications of gas lift. Various types of gas lift operations are discussed. The mechanical operations of flow valves are explained. Types of installations are analyzed. A detail design technique for the most efficient point of gas injection is outlined. Valve spacing calculations are presented. Flow valve operating pressure design is commented upon. Operational hints to increase efficiency are suggested, the closed rotative gas lift system and the future trend in retrievable gas lift equipment are mentioned. The advantages of gas lift are emphasized.

Automatic control instruments have a great deal in common with economic principles; they deal with supply and demand. Considering that an upset in a process is a change in demand, an automatic controller must be capable of changing the supply to re-establish process balance; therefore, automatic control may be defined as balancing supply against demand over some period of time. The period of time involved in making the supply equal to the demand may vary widely, and is primarily a function of process conditions.

You have come here in the hope of learning something about the Principles of Sucker Rod Pumping. I have been studying that subject for about 20 years and I am certain that I have much yet to learn. It is quite unlikely that you will leave here knowing all that is known about that subject. Sucker rod pumping, unfortunately, is an illusion, in that it looks quite simple whereas that problems involved are extremely complicated, and little understood. And, for that reason, many things we "know" about sucker rod pumping aren't true at all. By the work "principles" we mean the truths or facts upon which other facts or truths depend. It logically follows that we must start with the most simple facets if we are to comprehend the principles involved in sucker rod pumping and from them be able to reason our way to pertinent facts and conclusions.

It might be said that the fundamentals of sucker rod pumping are very simple. The plunger pump has been known for many centuries, and the mechanical and hydraulic functioning's of the modern deep well sucker rod pump are precisely the same as originally conceived. The materials and precision workmanship only have been improved.

During a pilot evaluation of a CO? water-alternating-gas (WAG) injection performed in the west Texas San Andres formation, operators discovered that CO? and water injections were being lost to a highpermeability layer in the upper portion of the formation. This problem was indicated by profile data and a lack of offset production-well responses. No offset producers indicated the presence of CO? however, CO? was discovered in an abandoned temporary injection well located 2 1/4 miles from the communicating injector. This discovery meant that, rather than reaching their target destination, injection fluids were traveling to the abandoned well through a high-permeability thief zone.

The centrifugal pump is a dynamic pumping device. One of the limitations of centrifugal pumps is their inability to handle significant quantities of gas. Two-phase fluids with several orders of magnitude difference in the density of the phases have always been very difficult to pump. This presentation reviews the nature of gas in its relation to well production with Electrical Submersible Pumps and examines historical methods for gas handling. It presents information on the gas handling methods and devices more recently introduced to the industry and quantifies limitations to two phase production with ESPs.

Enhanced oil recovery (EOR), by gas flood, has been a successful practice since the 1930's. One of the more recent gases to be used in these operations has been C02. Large natural CO2 production from fields in New Mexico, Wyoming, Mississippi, and Colorado have begun to supply EOR projects. Naturally produced CO2 gas undergoes three major process steps before being transported, via pipeline, to the end users: production, purification, and compression. The purification step is performed to remove other gas and liquid contaminants from the C02. Although other methods have been considered, dehydration by glycol absorption has been most widely employed. Early in 1984 an invitation was issued, by a major producer of CO2 gas, to test the efficiency of different separation equipment on problems associated with the purification of naturally produced CO2 and process by-products. This article presents the results of one series of tests which includes: liquid gas separation pre and post contactor, produced water purification, and unexpected hydrocarbon in glycol entrainment.

A basic objective of any oil producing company is to recover the maximum amount of oil from a reservoir with a minimum cost. Many of the deep reservoirs in the West Texas- New Mexico area of production will require deep artificial lifts. The installation of any method of deep pumping is costly and operation expenses are high. Consequently, oil operators are making ever effort to reduce costs in order to obtain reasonable profits from deep pumping wells. Lower operating costs will result in higher recovery percentage of one of our most important natural resources, cure oil.
The artificial lift of fluid from deep depths does not differ greatly in principles from that of pumping relatively shallow wells. Problems caused by corrosion, abrasion, or normal wear can exist in any lift installation; however, the problems inherent with any method of pumping are usually amplified with depth. A particular problem might be four time as troublesome with a 10,000-foot lift as it is with a 5,000-foot lift. This is to say that pumping from deep depths is expensive. Since there is only a small margin for error, it is essential that close control be exercised with deep-lift installations, and the costly problems involved in deep-well pumping deserve consideration and study. The percentage of total pumping wells which require deep lifts is relatively small, but it should be remembered that the number will increase and that even deeper pumping will be required in the future.

Substantial economies are obtained in many areas by depleting two formations simultaneously within the same well bore. The saving in initial investment of drilling cost and equipping a dual well is forcibly evident over the costs of drilling twin wells. Present day methods for the practicable and profitable production of dually completed wells have progressed to such a degree that as a matter of practical economics operators are virtually compelled to review the possible advantages of two zone production before starting additional drilling and work-over programs.

In the 15-20 year period since most oil companies divested themselves of company-owned drilling rigs, one problem has continually arisen: that problem being training of drilling personnel within these companies to successfully supervise a drilling operation made up of an assortment of drilling contractors. Due to many varying reasons, the type and amount of supervision that these drilling contractors have required have changed with time. Most oil companies today still feel that they need to train men in drilling techniques so that they can actually go to a rig and "make hole". The opportunity for these men to gain experience in this field is usually limited due to the ever-decreasing number -of wells drilled. Consequently, the company fears the day when the last of their company drilling personnel with actual rig experience reach retirement age.

Of major importance in the efficient producing of oil is to minimize workover operations caused by wellbore equipment failures. The most frequent cause of such failures is corrosion due to the corrosivity of produced fluids. The rate of attack can increase markedly as water production increases. Unless such changes are quickly detected, corrosion-induced failures can occur before an effective inhibition program can be developed. This paper presents procedures for evaluating the corrosivity of well fluids and determining when the rate of attack changes. Also included are brief discussions on various treating procedures and how the producing characteristics of wells determine the selection of the treating method. While selection of the proper inhibitor is of equal importance in a corrosion control program, it is usually based on laboratory evaluations and is beyond the scope of this paper.

In the early days of the oil industry, producers were in the oil business. In today's oil industry, producers are in the produced water management business. The emphasis has changed primarily because the majority of the produced fluid is water. This paper will deal with one major challenge facing the oil industry today - produced water. Handling produced water is costly; however, by employing good produced water management, additional revenue can be derived. This presentation will include the following: "Evaluating Present Water Equipment," "Internal Tank Designs," "Method of Skimming," "Salable Oil," and "Treating Reclaimed Oil."

It has been said that, "Artificial lift is the most important cost item in the oil industry today." This is a quote from the Petroleum Engineer, "The Revolution in Artificial Lift" February, 1969. The development and performance of an artificial lift system designed to reduce this important cost item is discussed in this paper. This artificial lift concept conditions produced well fluids for use as power fluid in a hydraulic system for single well installations to compete with sucker rod pumping or other single well lift systems. The power fluid conditioning unit makes possible a safe and economical method of lift that is simple, flexible, reliable and compatible with automation.

One major problem frequently encountered in waterflood projects is the poor quality of produced water used for reinjection. One of the main factors usually cited for poor water quality is a high solids content. Another common problem with produced water is excessive carryover from the treating facilities , which can result in a significant loss of revenue. The produced water treatment system used at the Willard Unit near Denver City, Texas, has been successful in obtaining a good quality injection water. This paper discusses the Willard Unit treatment system and in particular emphasizes the design and operation of the dissolved gas flotation cell presently in use for oil skimming and solids removal.