Liquid that accumulates in an air-drilled borehole after water-bearing zones are penetrated causes drilling problems that result in excessive compressor requirements and lost rig time. An automatic jet sub that aids removal of liquids that accumulate during downtime and helps lift slugs during drilling described. This device consists of a differential pressure valve mounted in a drilling sub. These subs are spaced in the drill string above the bit. A portion of the circulating gas is diverted to the annulus above the bit when required to lift liquid slugs. When the liquid is removed, the jet subs close and full circulation goes through the bit. Application principles of these subs are discussed.

Automatic lease operation fundamentally results in three basic factors which production operators always set up as primarily criteria for their operation: 1. Conservation of (a) hydrocarbon resources and (b) steel 2. Increased safety and efficiency of operating personnel 3. Reduction in initial capital investment. In order to get a clear picture of this new concept of lease arrangement, we should first break down into some broad categories the types of well production as well as the size and scope of individual leases.

The oil industry has utilized automatic controls and instruments for controlling processes and functions in the refining, natural gasoline and pipeline departments for a number of years. Only recently, though, have steps been taken to automate the handling of fluid and gas from the well head to the pipelines. Automatic lease installations now installed and operating have shown that the greatly increased economies and performance derived will provide tremendous momentum for full automation of oil and gas production.

The types of installations that can be made automatic and a method of selecting the proper equipment are discussed. The complete operating cycles of some automatic gas engine installations are explained, including starting, loading, protection for both engine and equipment, unloading and stopping. Matching horsepower to required output by speed and/or load modulation, idle running and intermittent operation are covered.

Managing plunger lift operation with electronic control has the potential to radically improve the production of fluid loaded wells. For this improvement to be realized however, several factors must be taken into consideration, and the control system must meet certain minimum criteria. For a control system to be successful it must address the needs of the operator, provide the control requirements specific to the physical constraints of the well, and incorporate a flexible and complete control system to empower the operator to manage the process of plunger lift with intelligent tools.

In competitive industry there has always existed a trend toward the application of automatic equipment. This trend has been stimulated by efforts to conserve two principal business elements; time and money. The inherent advantages of automatic methods over manual methods have been (1) higher degree of accuracy in control (2) greater speed of response (3) lower operating expense and in most cases, (4) lower initial investment.

Cities Service has three automatic tank batteries, all of which use positive displacement meters. All of these batteries are unattended and automatic in operation. Oil is produced, monitored, treated and run to the pipeline without manual intervention. Although positive displacement meters are the heart of these units, there are other components just as necessary and important to automatic custody transfer (ACT) of oil to the pipeline. This paper will discuss the ACT Units as developed by Cities Service with special emphasis on the components used to accomplish the necessary functions of automatic battery operation.

Emulsions (oil/water mixtures) have been known to exist since oil was first produced. The first early methods for dealing with this problem were to skim the oil from the top of a storage vessel and get rid of the rest by flowing it into streams or storage pits. The early refiners had their problems with handling crude oil containing water, because the expansion of a typical crude oil when heated to 700 degrees Fahrenheit is 60%, while water expands more than 1600 times (160,000%) as steam. Because of this problem, purchasers of crude oil limited the water content of their purchases and developed elaborate systems for dehydrating to be used for charge stock.

ARC0 Oil and Gas Company's Willard Unit is located in the Wasson San Andres Field, Yoakum County, Texas. Waterflood operations began in 1965 with tertiary (alternating water-CO21 operations beginning in January, 1986 in the southern part of the unit. There are currently 335 producers, 270 injectors, 13 test stations, one central battery, and two water injection plants. Automation was installed first in 1973 and has progressed in three primary steps. This paper highlights that progression by discussing its utilization and results.

Conoco. Inc. operates the Dagger Draw field in Eddy County. New Mexico (see Figure 1). The field produces 2500 BOPDI8500 BWPDil 1000 MCFPD from 35 wells on beam pump. The typical well utilizes an API 87 high strength rod design with either a 912 or 1280 conventional pumping unit running 8-9 SPM with a 168" stroke length. The 7,900-ft reservoir is under primary development. A 30-month study is documented during which automated Pump-Off Controllers (POCs) were installed to reduce the high rod failure in the field. Data collected for six months prior to installation indicated that 35 wells averaged 9.8 rod failures per month. In the 14 months following POC installation. Rod failures have been reduced 76% to an average of 2.4 per month. Automated surveillance of the POCs using a central computer has resulted in increased efficiency. Manpower requirements have been reduced by one employee in the field. A previously unknown seven to eight day variable production cycle was observed field wide. This discovery helps to explain the failure of Conoco's previous attempts to control the fluid pound or gas pound with time clocks.

The problem of increasing profits by decreasing cost has forced many innovations in all sections of the petroleum industry. The automation of its operations has been and will continue to be the major item in reducing cost. Automation means many things to each person, and there has been numerous papers presented covering each phase of automatic equipment. This presentation will be a general description of what one pipeline company has accomplished in its operations through the use of automatic equipment.

Finding effective, low cost prime movers for pumping units can be hard to acquire in today's market of deregulated electricity. The inability to adequately start and stop gas engines has always been a problem area. With the cost of electricity increasing, and the ability to operate wells when you want decreasing, the producer will have to take peak usage and availability of that electricity into consideration for their production cycles. The day may come when then electricity may dictate when the well operates and not the producer. This paper will introduce a completely new air actuated clutch design, and review several applications that have been used successfully in automating pumping units with gas engines. This new air clutch design for gas engines also teams with P.O.C."s, and telemetry to give the producer the ability to better manage their pumping cycles, saving time, money, and driving down repair and maintenance costs.

The performance of the centrifugal pump used in Electrical Submersible Pumps (EPS) is significantly degraded by the presence of gas in the fluid. This greatly reduces the applicability of the pump. Rotary separators, separating devices that used the pump shaft rotation to force the gas from the liquid were developed over twenty five years ago. In situations where even the rotary separator could not remove enough gas form the fluid, tandem or stacked rotary separators were often used.Improved models of rotary gas separators have been developed and introduced. In the development of the new separators, a large body of information was developed on the mechanism involved in the rotary separation. Parts of the lessons learned in the development of these new separators indicate that a tandem separator may be of little if any benefit to downhole gas separation.This paper reports on gas separator testing performed in a high pressure gas test loop. This testing concentrated on the possibility of benefit of tandem configuration on the new style gas separators. It examines and reports on where the benefits of tandems may occur.This information will be beneficial in designing and selection ESP systems in gassy applications.

This paper reports on the testing and development of a new generation of gas separation technology for Electrical Submersible Pumps. Active (rotary) gas separators were introduced to the market 20-25 years ago, and no major improvements have been made since Accurate testing of gas separators has always been fraught with problems, sometimes producing confusing and misleading information. An in-depth study and testing of the separators in a high pressure gas testing loop has indicated some methods to improve the gas separator performance. Finite element modeling, coupled with advanced CAD/CAM and fabrication techniques, has aided in a developing a new separator. This separator has improved both the efficiency and operating range. The information conveyed in this presentation will give the users of ESP insight into how the gas separation equipment is developed and tested and will also increase their understanding of the cost and effectiveness that can be expected in the application of ESP in gassy wells.

Horizontal completions in lower permeability formations often result in a need for effective hydraulic fracturing stimulations for many of these wells to reach economic production levels. Cost constraints seldom allow the use of methods such as cemented completions and individual fracturing of numerous zones with bridge plug isolation. Some newer methods require expensive downhole jewelry. By implementing a coiled tubing (CT) deployed hydrajet perforating method and pumping the fracturing fluid slurry down the CT/casing annulus, the operator can use lower risk liner completions (cemented or not). Individual zones are perforated, fraced, and then sand-plugged one at a time. With the ability to reverse up the CT between stages and after all fracs are completed there is only one CT intervention and one frac mobilization needed. The allowable frac rates can be quite high and stimulation costs are greatly reduced by being able to perforate/frac multiple times within the same day.

Through the years, oil operators have discussed the pros and cons of holding tubing backpressure in rod pumped wells. Although backpressure on tubing is not a panacea for every well, there are definitely applications where it can aid in the operation of a rod pumped system. Most commonly, backpressure is used to prevent a well from "flowing off" at surface when gas is present in tubing fluid column. Backpressure may also be used to increase differential pressure across pump valves when needed. It is beneficial to know when backpressure is needed and only use it when necessary to optimize pumping system performance This paper will discuss how tubing backpressure can be effectively used in some wells. It will also discuss the unintended effects of holding backpressure such as increased "slip-stream" flush volume, changes in polished rod loading, and possible increased power usage.

This paper describes how baked-on coatings are being employed as economical corrosion and paraffin control devices in the Permian Basin Area. To illustrate and explain the influence of "Quality Assurance" upon the economics which support having tubular goods coated, a string of tubing is followed through a baked-on coating process. It is concluded that the economics favoring baked-on coatings are no stronger than is the coating process.

Baker Hughes Drill Bits recently launch the new Talon Bit which was derived from years of engineering experience and reiterations of bit designs. Baker Hughes Drill Bit Engineers have tested many different frame styles that have lead to the optimized drilling and efficiency of the Talon Bit. The Talon Bit has continuously enabled operators to increase their rate of penetration, reach target depths with one bit which leads to cost savings. By enlarging the junk slot area and face volume of the bit, we are able to optimize the hydraulics and efficiently remove cuttings keeping the bit cool and clean. The blades of the Talon Bit have also been altered. The thinner Talon blades have allowed the bit to have a more open cutter face leading to an increase in instantaneous rate of penetration. Baker Hughes Drill Bit Engineers have not only adjusted the bit frame itself but also invested into the research and development of the Talon diamond cutters. Optimizing durability has been a constant priority for our cutting edge technology and increasing the durability of the Talon diamond cutters have made it possible for the Talon Bit to reach the ever challenging target depths.

Banks have been making loans secured by oil and gas production since the 1920"s. The nature of oil reservoirs was not understood very well at that time, and the early oil bankers were handicapped by a lack of reliable oil- and gas-reserve reports. The problem was compounded by wildly fluctuating oil prices. The development of instruments for obtaining bottomhole pressure and temperature, cores, and reservoir fluid samples and the development of the ancillary laboratory equipment for measuring the core and reservoir fluid properties paved the way for the development of reservoir engineering. These developments occurred primarily in the early 1930"s, and led to greatly improved reserve estimates. For the first 7 1 years after 1859 when oil was discovered in the United States, oil prices increased sharply during periods of shortage, but often plummeted when a major new field was discovered. The price of oil was $2.44 per barrel in 1920 but had declined to $1.10 per barrel in 1930. Then the East Texas Field was discovered, and the price of oil dropped to 10 cents per barrel. There was economic chaos, and this brought about "market demand" proration. There was surplus producing capacity in this country for the next 43 years, but the prorationing system led to reasonably stable oil prices. These two developments, the accurate estimation of oil reserves and stable oil prices, made widespread bank oil loans feasible. From a slow beginning in the 1920"s, oil loans have grown to be a major part of many bank loan portfolios. Banks have recently experienced difficulties with loans in some industries, such as cattle feedlots and real estate developments. Bank oil loans, however, have performed extremely well, with the help of the large oil and gas price increases that have occurred since 1973. Oil loans are attractive to banks because of the presently favorable economic climate, and because of the normal self-liquidation of oil loans through monthly oil and gas sales.

Many engineers, when faced with the necessity of designing a fracture treatment for a well, will either look to the experience of other operators in the field or will rely on a service company for the design. Although these courses of action have merit, they do not always result in the most effective treatment for a particular situation. It is essential therefore, that the engineer have a knowledge of basic design methods and an understanding of fundamental fracturing concepts if he is to intelligently recommend a fracture treatment for a well. This paper presents a brief summary of fracturing concepts and a method for determining the size of the treatment. It provides a sound engineering basis for designing a fracture treatment, especially in areas where there is little or no prior fracturing experience to act as a guide. With this design procedure the engineer can determine the amount of frac fluid and the quantity of sand to be injected. The discussion in this paper is limited to the conventional, sand packed treatment where the induced fracture is in a vertical plane. It is generally believed that in most cases the induced fracture will be vertical below a depth of about 3,000 feet.

Over the last decade the use of the pressure derivative as a diagnostic tool in pressure transient analysis has grown immensely. The modern well test analyst turns to the derivative log-log plot almost exclusively to formulate a first opinion on well test behavior. The pressure derivative essentially allows the analyst a magnified view of the distinctive pressure behavior associated with various wellbore and reservoir phenomena. This paper utilizes both real and simulated pressure transient data to illustrate common derivative responses due to selected wellbore and near-wellbore effects, reservoir types, and boundary conditions. Definitions of common well test analysis terminology are included. The information presented should allow individuals who are involved in well testing, but not necessarily confident in test analysis, to qualitatively comment on test results.

A typical submergible electric pumping unit is composed of seven basic components: electric motor, multi-stage centrifugal pump, protector, power cable, motor flat cable, switchboard and an auto transformer, single three phase or a bank of three single phase transformers. All of the above equipment is manufactured in numerous sizes and types to fit the well specifications, such as casing size, desired producing volume, total lift, electrical power supply and environment. In addition to these basic components, various auxiliary items are used. Some are required, while others are optional. The most common required items to complete an installation are: Cable clamps, cable reel, reel supports, shock absorber, shipping boxes, tubing support and, in many cases, a swage nipple. Other optional items not required for an installation, but recommended where applicable are: Flat cable guards, check valve, bleeder valve, centralizers, motor jackets and downhole pressure sentries. In some instances, usually in remote areas, engine generator sets are used instead of purchased utility power. Such generator sets may power multi-well installations or individual wells. In the latter case, transformers can usually be eliminated by supplying an alternator which is wound to supply the proper input voltage (required surface voltage).

It is becoming increasingly important for technical personnel in the petroleum industry to have a background in filtration and separation techniques. One of the principal reasons for this need is demonstrated by the number of enhanced oil recovery (EOR) projects currently in operation. Anytime contaminated fluids are introduced into a subsurface formation there is a risk of damage. In the case of water and gas flooding operations where large volumes of fluid are injected, levels of contamination become acute problems. As an example of a systematic approach to filtration problems, this communication describes the component selection and field operation of a pilot system for the removal of solid and liquid contaminants from waterflood injection water.

Packers are run in oil and gas wells primarily to confine fluids. Usually the objective is to confine high-pressure or corrosive fluids and/or, in the case of multiple completions, to confine the fluid to specific tubing strings. Many side benefits are obtained because of the confinement; such as, protection of the casing from high-pressure or corrosive fluids, separation of zones in the well bore, directing the flow of treating fluid, and also as a safety feature. Various questions always arise; e.g., how much weight to set on the packer, how much do you pull, how much psi will it hold, how much do you pull to release the packer? There are a number of computer programs that have been written to analyze and predict tubing and packer loading forces and tubing movement. The computer certainly has its place, especially in the deeper wells where the conditions become more extreme and critical and the calculations become more complex. However, most applications can be quickly and accurately analyzed by applying a few basic calculations to determine the net result of the various operating conditions. Quite often it is possible to rely on an experience factor to design a hookup; but for more extreme conditions, the present and future well conditions should be anticipated and a hookup designed that would be compatible with these operations. This discussion will concern itself with calculations involving the hydraulics and various other forces as they affect packers. An attempt will be made to focus the emphasis on calculations that can be readily made at the wellsite without sacrificing accuracy. It would be oversimplifying the subject to say that all packer application problems are pressure and area calculations; but many of the calculations simply involve pressure and area. A little further in this discussion we will touch on tubing movement calculations involving piston (axial), helical buckling (corkscrewing), ballooning (radial) and temperature (axial). In a total analysis, many complex theories are utilized but that is not the purpose of this paper.

Mainly due to its long history, sucker rod pumping is a very popular means of artificial lift. Nearly two thirds of the worlds producing oil wells are on this lift. This paper reviews concerns that producers are faced with today when using inadequately designed sucker rod pumping designs, and suggest basic methods to assist with those concerns. In general, sucker rod pumping applications can be very effective when properly designed.