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This application was done in Manantiales Behr Field, REPSOL YPF, well AEA-507. This is a field located 30 miles northwest of Comodoro Rivadavia City, in Chubut's Province. The field's characteristics are heavy oil, very high viscosity, low production (1 5-60 m3/day), medium water cut, medium depths (1200 meters) and sand. Besides, the weather conditions are very harsh during the winters, getting below 0C.

Manufacturers of down-hole sucker rod pumps have developed materials, coatings and treatments for barrels and plungers. Some of these have become standards in the industry while others have been tested and either did not meet expectations or were not economically viable. This paper will review historical, current and new materials, coatings and treatments for down-hole sucker rod pump barrels and plungers.

Completions for thermal recovery installations are closely related to the many new and sophisticated approaches to well design which have come of age during the last decade. This writer likes to compare them with completions in the 15,000 - 20,000 ft range, to high pressure gas completions in corrosive environments. perhaps to wells on platforms in deep water or completed by TFI methods.

In 1972 a carbon dioxide/water injection project began in the SACROC Unit, Kelly-Snyder Field in Scurry County, Texas. The injection of CO2 and the highly corrosive produced water has created some very unique problems with downhole equipment. New materials of construction, new design parameters, and new treatment methods have been developed to deal with these problems. The paper describes the corrosion problems encountered with submersible pumps, sucker-rod pumps, tubing, sucker-rods, and other downhole equipment, and it describes the solutions found for these problems.

The Downhole Diverter Gas Separator increases the liquid capacity and gas separation capacity over conventional poor boy or Improved Collar Sized downhole gas separators. The increased separation capacity of the diverter gas separator is provided by using the larger tubing-casing annulus for both gas separation and liquid separation. A simple movable rubber seal is used to divert the flow of liquids and gas vertically from below the rubber seal through a central tube approximately 5 feet in length.

The Downhole Dynamometer is a tool designed primarily for the acquisition of sucker-rod load and position data at any point in the rod string. The tool is completely sealed, battery-operated, and microprocessor-controlled to sample the various parameters at specific times and sampling rates and to store the data digitally in a nonvolatile memory for later retrieval. Other parameters sampled are temperature and pressure and, with the present design, bending data is also collected. Axial position is derived from acceleration.

The Downhole Dynamometer is a tool designed for making dynagraph measurements at any point in the rod string. The tool is completely sealed, battery-operated, and microprocessor-controlled to sample axial load, position, lateral acceleration, fluid pressure, and temperature at preprogrammed times and sampling rates and to store the data digitally in a non-volatile memory (Figure 1). Load is measured at three points spaced radially equidistant around the body of the tool enabling the derivation of bending and buckling loads. Rod velocity and acceleration are also measured.

Downhole Oil Water Separation (DOWS) is becoming one of the key technologies of the oil industry and to reap the benefits promised by this concept, a new system has been developed to separate oil and water in the wellbore. The first test of the system - the Triple Action Pumping System (TAPS) - will be described in this article. The new system has accomplished a number of industry firsts in oil/water separation. The potential of DOWS to improve revenues, reduce expenses and investments, and protect the environment when the right conditions exist has been described in previous article.

A novel image acquisition system has been developed that will enhance our knowledge of downhole pumps. This system, comprised of a video camera, digital frame grabber and image processing routines, has been integrated to the downhole pump test fixture at the University of Texas at Austin where in the past pressure at various point of interest around both the standing and travelling valves have been recorded.

With today's economic condition, competitive market, and customers world wide clamoring for lower prices, the need to maximize the economic operation of an oilfield has never been greater. This paper is directed toward abrasive wear and increasing pump barrel life. The first step in increasing the life of a pump barrel is to understand why it wears out. After we grasp the cause of wear we can design or select a product that wears slower. Wear cannot be stopped but only slowed.

The Drill Stem Test (DST) is a temporary well completion, which is made in the early production life of a potential reservoir to determine both the quality and quantity of produced reservoir fluids. This can be done prior to completing the well. The drill stem is used to lower the packer(s), downhole valve assemblies and other auxiliary tools to the bottom of the hole. The packer is a device which expands and effects a seal with the wall of the hole and isolates the zone to be tested from the drilling fluid in the annulus.

Damaged pipe, especially in horizontal applications, is costly. The large number of planned horizontal drilling projects
coupled with the expense of pipe replacement and fishing operations made it imperative that Mobil E&P gain a better understanding of drillpipe life. Previous internal studies of failure flurries have shown that excessive doglegs, high H2S environments, and improper specifications or makeup on tubing connections can accelerate fatigue leading to failure. The effect of high bending stresses on drill pipe connections is also a concern.

Prior to the 1973-74 Infill Program, the Shell operated Denver Unit, Wasson San Andres Field, Gaines and Yoakum Counties, Texas (Fig. 1) included over 900 producing or injecting wells. Upon project completion in October 1974, the 1973- 74 Denver Unit Infill Program added 120 wells (14 injectors, 3 replacement wells, and 103 new producers) to this total. The 1973-74 program was sufficiently different from previous Denver Unit programs to require some changes in techniques and equipment.

With the use of invert emulsion fluids, environmental responsibility has increased the cost and liability associated with the disposal of contaminated drill cuttings. In environmentally sensitive areas it is unlikely that any discharges of contaminated cuttings will be permitted and responsible treatment methods must be found to minimize future liability. Development of an invert emulsion drilling fluid designed for both the high performance drilling and optimized treatment of contaminated cuttings has been a key in minimizing environmental impact.

Drilling is required for the exploration and production of almost all forms of energy and mineral resources found in the earth. Current drilling activity in this country is large and working near the industrial capacity. For example, the petroleum industry alone drilled approximately 145 million feet of hole in 1974 at an average cost of $24 per foot. The uranium industry drilled an additional 22 million feet to bring the total drilling cost to almost $4 billion in 1974. This figure was exceeded in 1975 and projections for 1976 are higher still.

Before 1950, drilling strings contained few drill collars, and the hole depth was shallow enough so that grade-E drill pipe easily satisfied most requirements for drilling and drill-stem testing. In 1957, when Great Western Drilling Company drilled the Phillips Petroleum Company Montgomery A-l to 23,400 feet, engineered drilling strings became necessary. Between 1957 and the time the API published RP7G, drilling-string design was a daily necessity for drilling engineers to avoid operational problems and to satisfy contractural requirements.

This paper presents a case history of the methods used by Exxon co., U.S.A. to drill the St. Lawrence Field in Glasscock County, Texas. Lightweight oil base mud was used to combat salt and lost circulation, while brine water weighted with hematite was used to drill an abnormally pressured section. Two-stage and tack-and-squeeze cementing were used to place cement across lost circulation zones. The lightweight oil base mud was technically successful, yet proved uneconomical. In contrast, the hematite was cost effective as a weighting material.

In 1982 the Employment and Productivity Sub-Committee of the U.S. Senate Committee on Labor and Human Resources held a series of four hearings on United State's productivity performance. Testimony was heard from witnesses representing education, science, industry, high technology, labor and government. During those hearings, information surfaced that was serious enough to warrant holding a fifth hearing. Seventy bit lion dollars down the drain. Think about it.

DTS sensing is an emerging technology in which a local operator used on 16 wells to determine the effectiveness of acid treatments. The technology uses a fiber optic cable to read temperature realtime downhole per foot along the wellbore. This allows the service company to validate fluid placement. The effectiveness of the acid treatment can now be determined. Effectiveness can also be determined by how much improvement in production takes place after the job. In the case studies observed, effectiveness was determined during the pumping of the job with DTS sensing rigged up to the well.

The term "dual completion" refers to a method of producing two zones through the same well bore without co-mingling of fluids. A dual completion is one that promises greater economy. During recent years the percentage of such completions has been greatly accelerated, due to mounting development costs. Because of the success of dual completions, and the favorable economic aspect, there is no reason to predict a downward trend. Equipment manufacturers are constantly redesigning and improving their equipment to meet the demands of equipment applications.

The need to produce large volumes of fluids from secondary recovery wells, and to produce normal levels of fluid from deeper wells, made possible an innovative artificial lift option using a Dual Displacement Pump.(Fig. 1) Reciprocated with a standard beam pumping unit using coiled tubing, this production system (patent pending) consist in reciprocating a plunger of a down hole pump, were both motions of the pumping unit are utilized to convey fluid to surface.

In 1994 Texaco personnel viewed chemicals as the primary means to reduce water handling costs. They recognized from downhole videos that oil and water remain separated in the tubing-casing annulus. Capitalizing on this revelation of "gravity segregation," they conceptualized a dual-ported, dual plunger rod pump to produce oil and water from the annulus on the upstroke while injecting water on the downstroke. Texaco and Dresser jointly developed this pump and named it the Dual Action Pumping System (DAPS). In January 1995, the first generation prototype was installed.

This paper reviews our experience, dating from 1953, with dually completed wells equipped with tandem pumps (two pumps actuated by one rod string). In this span of time newer designs in dual-zone equipment and packer-tubing combinations have antiquated the initial installation. Subsurface schematic drawings depict seven deviations in equipment installed in various wells, which encompass most of the major techniques and assemblies.

This technology utilizes a thixotropic, in-situ polymerized, gelation system. It is designed to prevent gravity slumping to form a chemical packer in horizontal and deviated wells. This system has relatively low viscosities at surface temperature but develops its thixotropic properties in a time frame of 20 to 30 minute as temperature increases while being pumped down hole. This thixotropic blend can be used in wells with bottomhole injection temperatures ranging from 100oF (38oC) to 180oF (82oC).

The dynamic properties of nitrified cements are dependent on the temperature and pressure state of the downhole system as well as the physical properties of the base fluid. The density, viscosity, volume, and rate of a nitrified fluid change as the downhole temperature and pressure circumstances change. Mathematical formulas based on gas density, molecular weight, specific gravity, and Ideal Gas Law provide the means of calculating the fluid properties at anypoint in its pumping history.