Any fifty-minute discussion of artificial lift can be only an overview. It is impossible to cover the four major types -- rod pumping, electrical submersible pumping, hydraulic pumping and gas lift -- comprehensively in such a time frame. Nonetheless, I hope to give you a little better understanding of what the major considerations should be when selecting, designing, installing, operating, or repairing high rate artificial lift systems. For those who desire more information, I have prepared a bibliography of what I consider are the best published artificial lift papers.

The method of artificial lift using the plunger lift system has been, until recently, the most overlooked and neglected of all the lift systems being utilized today. Why? For the most part, it has been misunderstood by operators, or in some cases operators have experienced failures due to antiquated systems, or misapplication on wells not suited to this form of lift. What form of artificial lift could be more efficient or economical than one which allows the energy produced by the well to produce the well? Plunger lift does just that. Yes, the energy stored in the formation in the form of gas and pressure is used to produce the well's own liquids to surface by using a piston as an interface between the liquid slug and the drive gas. This is known as plunger lift. In the past several years, advancements have been made in plunger lift equipment and technology. First, it is appropriate to review how a plunger system works, and what it does.

The method of artificial lift using the plunger lift system has been, until recently, the most overlooked and neglected of all the lift systems being utilized today. Why? For the most part, it has been misunderstood by operators, or in some cases operators have experienced failures due to antiquated systems, or misapplication on wells not suited to this form of lift. What form of artificial lift could be more efficient or economical than one which allows the energy produced by the well to produce the well? Plunger lift does just that. Yes, the energy stored in the formation in the form of gas and pressure is used to produce the well's own liquids to surface by using a piston as an interface between the liquid slug and the drive gas. This is known as plunger lift. In the past several years, advancements have been made in plunger lift equipment and technology. First, it is appropriate to review how a plunger system works, and what it does.

It can be beneficial to store generic cement slurries whose set times have been delayed for weeks, then modify the bulk slurry properties, such as density, and activate them just prior to conducting the cementing job. Such technology offers distinct advantages in situations when the storage space is at premium or bulk blending facilities are not located close to the job site. Even though this technology has been around for about two decades, implementation of the technology has been plagued with problems of slurry gelation during storage, settling, free water development and unpredictable activation. This investigation discusses details of improvements to the compositions and the processes which render the technology amenable to implementation in a wide variety of applications. The slurries are designed to provide stable rheology up to four-weeks by manipulating the particle size distributions. The versatility in slurry design to meet cementing requirements for a variety of well conditions will be demonstrated.

The presence of small amounts of free or emulsified oil or oil coated solids in produced brines can adversely affect the properties of that brine in waterflooding and enhanced oil recovery projects. Likewise, the disposal of such oily brines can present a problem if the brine is being injected into a tight formation or, in the case of offshore platforms, if the brine is being disposed of overboard. Even if no difficulties are encountered in the reinjection or disposal of oily produced brines, the economic advantage of recovering even several hundred parts per million of residual oil from the brine should be considered. In many cases, the cost of the water clarification chemical required to recover the residual oil is small when compared to savings realized by recovering the oil. A large portion of the oil in oily produced brines is, in fact, emulsified into the water as a "reverse" emulsion. Such emulsions can be quite stable and require a long period of time to separate, due to stabilizing forces within the emulsion. Once recognized some of these forces can be neutralized by the addition of certain water soluble demulsifiers. A discussion of oily brine clarification, some theoretical considerations of emulsion technology, and a case history showing the economic advantage to residual oil recovery are included in this paper.

Between 1995 and I997 Oxy's South Wasson Clearfork Unit had experienced severe asphaltene plugging and some significant gas cycling from C02 flooding. An area of the field became known as Asphaltene Alley due to the high amounts of asphaltene plugging. With an aggressive program of chemical treating and paraffin cutting, failure frequency moved from I to .5 during this period. In 1997, due to the industries economics, the C02 flooding was reduced from 25 mcf to 5 mcf for the 98 producers in this field. As economics improved Oxy planned to resume C02 flooding in the second quarter of 2001. Oxy also planned to infill drill in an area of this C02 flood that had already accumulated unrelieved C02 build up. Oxy anticipated continued severe asphaltene plugging and gas cycling in this area. Oxy teamed up with strategic partners to proactively improve run times to be closer to the company average of. 19. The method selected was to run large volume compression pump designs internally coated with Teflon. The large volume vane openings were to help pass larger asphaltene solids and larger volume gas slugs. The Teflon would provide a "slicker", lower friction coefficient, to avoid accumulating asphaltenes and to provide some additional throughput efficiency. The efficiency difference was measured by testing bare stages then retesting the same stages coated with Teflon. Oxy has run 20 subs with this method. The earliest unit was run 12/15/00. The infill drilling, unrelieved C02 pressure, and asphaltene production were realized in 2001, however the new C02 flood has been postponed. No units have failed due to asphaltenes or gas cycling yet. There were two failures not related to asphaltenes or gas cycling that gave favorable indication of the effectiveness of the coating. Further results will be presented as this project continues.

With over 1,000 installations, solid expandable tubulars have established a legacy as an enabling technology that mitigates a variety of unfavorable wellbore conditions without sacrificing hole size. In addition to the technical solutions, operators have realized significant savings by being able to conserve on pipe needs, consumable use, and environmental disturbance. Incorporating these systems into the initial wellbore plan reduced overall costs of some wells by up to 30%. Projects previously deemed cost prohibitive gained economic feasibility. This paper describes the operational process of how solid expandable tubulars have been used in varied environments and conditions to solve a broad range of downhole problems. Actual case histories are used to illustrate how this technology was advantageous to projects, be it economic, technical, or environmental. This paper explains the planning and implementation process to ensure that maximum value of the solid expandable system is attained.

This paper discusses the use of a data acquisition system to provide higher quality cementing services at lower costs. Using low power microprocessors combined with reliable sensors for pressure, rate and density measurement of cement slurries the data gathered can be used to help prevent abnormal jobs, keep slurry density within program limits and provide system maintenance indicators.

More than ten years ago oil and gas producers expressed the need for a generalized system for the automation of well head operations. A well-head supervisory controller has been developed that provides a general, simple, small, low cost hardware platform with extensive firmware capabilities for well head automation. The operating firmware for the system is written in a high level language, which allows flexible application development at reasonable cost in a reasonable time. Communication for the system employs a widely used, well known, standard protocol. To date, firmware applications for the unit include: general RTU, pump off control, AGA-3/NX19 gas flow measurement, gas flow data logging, plunger lift control, intermittent gas lift control, continuous Gas lift control, water injection control, CO2, injection control, liquid flow control, gas flow control, pressure control and tank level measurement. Additional applications including compressor monitoring and control, VRU (vapor recovery unit) control,LACT unit monitoring and control, net oil computer applications, oil theft detector, hydraulic pump monitoring and control and ESP monitoring and control are in the queue for development. The scope of well head and facilities applications for the system are only limited by the types of equipment in the field and imagination of the user and the manufacturer.

Patented new technology was recently introduced to the petroleum industry that reduces the Ming cost per barrel of fluid by containing the spectrum of abrasive particles that damage the rod pump. This technology includes a stainless steel membrane system with specifically tailored micron rated openings. Production operators throughout the world continue to document dramatic economic benefits when a dedicated abrasive particulate control system is used to protect the crucial tolerance of the rod pump plunger to barrel interface. Building on our 1994 Southwestern Petroleum Short Course technical presentation,

This paper will share the experience and information gathered from the installation and/or operation of over 500 Automatic Casing Swab (ACS) systems. The information provided will assist an operator to determine if a well might benefit from ACS technology . This paper will review the history of the ACS and its evolution to the present day proven dependable tool. A discussion of the operating principles of the ACS will illustrate the flexibility and wide ranging applications of the ACS system in many types of gas reservoirs. The economic success of an ACS conversion is largely dependent upon the selection of a well candidate that can benefit from the unique characteristics of the ACS system. This paper will develop a criterion that will allow an operator to evaluate his wells to determine which wells are likely to benefit most from conversion to an ACS production system. Well characteristics known to hinder successful ACS conversions will be discussed. This paper will compare and contrast the operating principles of the ACS to tubing plungers, pumping unit, swab, and open flow wells. The paper will discuss the application of ACS technology to new wells as an initial production method. A well must be properly conditioned before an ACS system is installed. The paper will offer a detailed step by step ACS system installation procedure. Safe operating practices, start-up, and production operations will be discussed. Routine preventative maintenance and troubleshooting will be discussed to assist an operator to minimize remedial services that might be required should the ACS tool cease to operate. Simple preventative maintenance procedures keep the ACS operating at peak performance. Case histories will illustrate the positive impact that an ACS system can have on well production and operating expenses. The case histories will also highlight the types of wells that might receive the most benefit from ACS technology.

A detailed discussion pertaining to the selection of automation controls and unit equipment, as well as battery layout design and production sampling.

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.