Since its introduction to the oil and gas industry approximately five years ago, the consumption of line pipe in thinner than standard wall thickness has grown to the extent that now its utilization in oil and gas lines has become commonplace. Within the last two years this thin-wall concept has grown to embrace oil well casing and tubing as well. This paper will attempt to list some of the current applications of thin-wall pipe as well as the sizes and wall thicknesses available.

Previous advances in biotechnology have provided significant contributions to the oil and gas industry. Enzymes have been used for many years as low-temperature gel breakers. The previous enzyme products were non-specific mixtures of several different, non-isolated enzymes. Degradation by these systems resulted in the creation of polymeric fragments of widely varying size and damage tendencies. Recent biotechnical research has led to the identification of specific enzyme complexes to effect much improved degradation of polysaccharide polymers. The new technique utilizes substrate-specific enzyme complexes to hydrolyze the polymers to as little residue as possible. Neither the crosslinker type nor the degree of polymer derivatization interfere with the ultimate enzymatic degradation of the polymer.

For many, their first introduction to fiber optics was the decorative lamps of the late sixties. A group of optical fibers was tied together at one end and splayed out in a fan at the other. A bright bulb at the tied end illuminated the fibers, and light emerging from the loose end made them sparkle. It created a lovely effect, but had little practical use. Fiber optic technology has come a long way from the glittering lamps of the sixties. During the seventies, the telecommunications industry began to experiment with fiber optics in telephone circuits. From there, the growth of fiber optic applications has been explosive. Fiber Optic application is now becoming commonplace in our homes and businesses carrying not only telephone communications but also data, cable television, internet and security functions to name a few.

Numerous types of pump off control devices have been available to producers and operators since the late 1960"s. Since that time, pump off controllers have proven themselves to be invaluable in reducing lifting costs and increasing pumping system efficiency. This technology has, in general, been applied only in cases where economic justification is assured. Sadly, marginal (or stripper) production does not justify the expense and maintenance of most controllers. Therein lies a paradox - the wells that could economically benefit most from the application of pump off controllers were excluded from consideration due to economic constraints. The need for a simple, inexpensive and reliable POC became abundantly clear. By taking a unique approach to the detection of pump off, D-JAX Corporation of Midland, Texas has been able to reduce the complexity of pump off controllers, making them more reliable and less costly. A large majority of marginally producing wells are now within the economic threshold of pump off controller applications. This paper discusses the required functions and attributes of a pump off controller, proper selection of wells for successful pump off control application and a low cost, reliable means for the detection of pump off. Case studies will show how pump off control has been successfully applied to marginal (and other) producing wells to lower lifting costs, enhance pumping system efficiency and increase profitability.

A recently developed SPC program from Nalco/ Exxon Energy Chemicals, L.P. can significantly increase control of rod pumped wells. The program is applicable to automated pump off control(POC) systems where the controllers communicate with a common host. The program was derived from a need by Amoco to more effectively monitor paraffin deposition on tubulars in deep commingled wells. These wells experienced severe paraffin deposition resulting in costly well repairs. While the treatment method was important, the lack of an effective monitoring tool was critical. Amoco wanted a predictive monitoring tool that would warn them of paraffin in build up before it became a serious problem. Proactive monitoring of this type is one way to add value to automated monitoring systems. We learned that how well a rod pumped well is performing is a function of the data available from the POC and that applying SPC to this data will result in tighter control and improved operating efficiency.

Accurate and timely information is necessary if oilproducing facilities are to be operated properly. The operation of oil-producing properties at the optimum degree of efficiency is rapidly becoming an absolute necessity in the present social, economic, and political climate. The rates and volumes of the oil production, produced water, well test, and injection water are all important parts of the required information. It is not reasonable to expect a high degree of efficiency without this information being available. This paper discusses one phase of the continuing effort to provide this information to the operating personnel in the best possible manner. This effort is in fluid measurement. Several production units were formed in the Slaughter Field in Hockley and Cochran Counties in West Texas in the mid 1960"s; they were placed under waterflood soon after the units were formed. Meters were installed as a part of the initial water injection system. The injection lines were laid in a trunk and lateral system and, therefore, the individual injection-well meters are scattered throughout the field with a central remote readout capability. In the nearly 15 years since this metering system was installed, there have been technical advances in the art of metering, and economic conditions have also changed. A significant improvement in metering technology has been the development of sensing devices which make possible more positive detection of primary signals of low intensity. The economic changes have, of course, been the increased cost of equipment and labor. The cost that we are primarily concerned with is the one which we have the most control over: the cost of repair or maintenance. These two changing factors, coupled with the increasing importance of operational data, brought about the study of the application of the vortex meter as a possible improvement in metering systems.

There is a generally held opinion among the users of subsurface rod pumps that those pumps built to the specifications of API, Spec 11AX, have the following characteristics: 1. Their design is excellent with little need for improvement. 2. Equal quality can be obtained from various authorized manufacturers by simply specifying dimensions and materials in broad generic terms. 3. The individual design of pump parts has little or no bearing on pump performance. The author contends that these opinions are erroneous resulting in millions of dollars of unnecessary expense each year for the repair and maintenance of rod pumping equipment. To prove his contention he traces the history of the standardization program considering industry requirements, standardization goals, and the design options left open to the manufacturer/user team. He then discusses design details of some of the rod pump components that can cause major differences in pump performance and run time. In conclusion it is recommended that users consider all these factors to improve pumping system performance and reduce lifting costs.

The concept of the Area Waste Management Plans (Plan) for use in a company's drilling and production operations is explained. The objective of the Plan is to improve a company's waste management performance by developing appropriate waste strategies and communicating them to the field operations personnel handling the wastes. The Plan provides a process for identifying appropriate waste management strategies in a specified area's operations. These strategies consider current regulatory requirements, company policies, economic and practical factors. Management practices covered in the Plan include minimization, storage, handling, and disposal. Once developed, these strategies are communicated to field operations through a document specifically designed for effective use by field drilling and production personnel handling the wastes. The Plan's objectives, development, content and possible alternative applications are presented. Examples are given from the development of an actual Plan.

Proper matching of artificial lift equipment and technology to the specific problems of specific wells and reservoirs at acceptable cost is a rather sophisticated engineering exercise. Despite our current influx of engineering talent, people fully qualified to design and oversee the best possible artificial lift installations are in short supply. And those who are fully qualified very likely have other demands on their time.

A desire to return to operations in the simpler, single string form, yet maintain multiple zone allowable, formulated by the economic squeeze was the need which created the multiple completion choke assembly. A pressure production base was established as the means of allocating production, but this type of test procedure creates an economic burden which must be eliminated when a well moves to artificial lift status. A review of past allocation means, the new rules which govern multiple completion chokes in flowing and artificial lift wells, and installations utilizing improved producing techniques with pronounced savings are discussed.

A leak in the high pressure packing of a artificial lift system hydraulic pump has the potential of causing environmental pollution, safety hazards, loss of energy and costly clean-up. The subject of this paper is a system that prevents the product being pumped from becoming exposed to the atmosphere and surround areas. The technology to be described transfers the pressure of the product being pumped to a sacrificial barrier fluid of known characteristics. When the seals wear sufficiently to leak, only the environmentally friendly fluid leaks to the atmosphere. The technology can be built into new equipment or be retro-fitted to pumps in service with the proper modifications and sealing assemblies. The paper includes photographs of the Hydro-Balanced Stuffing boxes for sucker rod pumps and a diagram of the artificial lift pump improvement. The presentation will include slides and graphics of the Hydro-Balanced Packing System.

The purpose of artificial lift equipment is to do work by adding extra power to the produced fluid so that the fluid will flow to the surface. The power added lifts the produced fluid to the surface at a rate higher than the well power can provide. The power is added to the fluid by some type of downhole pump or gaslift. "Artificial Lift Efficiency" is a way to calculate how effective a particular type of lift equipment is in adding power to lift the fluid. In the literature there are many definitions of artificial lift power efficiency, but there is not one particular accepted equation. Reference 1 lists and reviews a number of references, which provide a variety of expressions calculating artificial lift efficiency. Also this reference compares a number of ESP vs. Beam Pump wells with electrical or power efficiency. However, in the paper it is shown that the definition of efficiency that was used in that study is subject to some unexpected variations if the surface pressure or amount of gas produced through the tubing is varied. Because of this, the definitions of artificial lift efficiency are reviewed and a standard equation is recommended.

When evaluating artificial lift in a CO2 flood, certain factors must be taken into special consideration. This statement is especially true if the reservoir is a sandstone without H2S. Such conditions exist at Postle Field in the panhandle of Oklahoma, making it a field of unique nature. Under normal considerations, when CO2 is injected, it mixes with water and produces a weak carbonic acid. If the reservoir is a carbonate, the rock will buffer the acid. If H2S gas is present, it also offers benefit and provides further buffer to the acid. At Postle Field, however, neither is
present. This field produces out of the Upper Morrow Sandstone which contains no carbonic cementation. In addition, it is an extremely corrosive field, which makes artificial lift very complex and dangerous. Postle Field has a robust number of wells that have either been lost or in danger of being lost, due to problems created by corrosion. This paper will discuss what is taken into consideration when designing artificial lift for the corrosive nature of Postle Field.

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.