From the selection process to installation and continued maintenance, the Tubing Anchor Catcher (TAC) is one of the most important tools in achieving efficient pumping operation.

Is your company likely to have worn tubing couplings or holes worn in the casing caused by tubing movement in the next few years? Are the tubing threads or even the body of the tubing likely to break by repeated stresses of transfer load? Do you think that there is likely to be a loss of efficiency in pumping due to movement of the tubing at the pump end? Could it be possible that low pump efficiency could be due to the leaky thread in the tubing, resulting from the tubing threads working? If the answer is "Yes," then it is entirely possible that you should use tubing anchors.

The goal of the work in lining tubing is to be able to place a liner or velocity string, without necessity of a conventional rig, into a well with minimum time disruption to production This paper discusses the application techniques and history of in-place repair of downhole casing and tubing. Over 230 wells have been lined with plastic and several plastic velocity/siphon strings have been installed. Technology development is necessary to extend the plastic lining techniques to deeper and hotter wells. Plastic well lining is discussed and successes and limitations are explored.

A slightly, acidic (pH of 5.8-6.3) Tubing Clean-Out Fluid has been evaluated in the laboratory and in the field for use as a pickling fluid to replace the traditional acids. This fluid's capability to remove iron scales on coiled tubing, prevent or delay rust from reforming, clean up commercial pipe dopes and reduce corrosion rates, was compared to traditional hydrochloric acid in laboratory studies. This fluid performed as efficiently as 15 wt% hydrochloric acid at 140_F in removing rust/iron scale as well as pipe dope from the workstring with lower corrosion rates at typical bottom hole temperatures. Furthermore, a work string treated with this fluid retained a protective coating that resisted re-oxidization for up to 30 days. Also, several case histories detailing the product's field use for pickling completion workstring are discussed.

The purpose of this paper is to outline the types of tubing joints and combinations of tubing that are considered satisfactory for use in dual wells, completed with two or more independently hung tubing strings. Field experience in running two or more independent strings of tubing has indicated certain running clearance requirements. The clearance can be calculated for the various dual well conditions. Many of these combinations are shown on clearance charts. The use of two or more tubing strings in dual wells appears to offer many advantages for rod pumping, hydraulic and for gas lift systems or combinations of any two of these methods.

The bottom of a string of unanchored tubing in a rod-pumped well moves up on the upstroke of the sucker rods and down on the down-stroke. The lower portion of the tubing string also buckles around the rods as they move up and goes straight as they start back down. Both vertical movement and buckling are caused primarily by those well pressures to which the tubing string is exposed. Decreased pump efficiency and abnormal rod, tubing, pump and casing wear are some of the detrimental results of this movement and buckling. Several past publications explain how a tubing anchor stops movement and keeps the tubing straight but none show how much this movement, which is actually the loss in pump stroke, might be. This paper first reviews the theories related to movement of the bottom of a string of freely hanging tubing in a pumping well and presents equations for calculating its amount. It then shows how a tubing anchor can be justified through increased production brought about by increased pump efficiency. Knowing the amount of cyclical movement will also give some indication of the reasons for excessive downhole wear. The paper also describes the various types of tubing anchors and includes some actual field cases which verify the advantages of anchoring tubing in rod-pumped wells.

Previous research and publications have established that clear and effective communication between the casing and the reservoir formation is an absolute requirement for an effective oil or gas well completion." As wells are drilled deeper and casing strings become smaller, the ability of jet perforating guns to penetrate the well bore effectively is greatly reduced. In wells exceeding l&000-foot depths one or more of the following situations usually exist: 1. Combination casing strings involving small bottomhole ID 2. The necessity of using small perforating guns due to well design 3. High compressive strength rocks which decrease the penetration of jet guns 4. High bottomhole temperatures which can reduce the penetrating effectiveness or performance of the perforating gun and in some cases render it inoperable 5. Excessive completion costs due to items 1 through 4. Because of these factors, the completion of such wells successfully, safely, economically, and satisfactorily has become an ever-increasing challenge. Present completion techniques of perforating usually employ the use of a shallow penetrating jet perforating gun run on wire line. When penetration is not sufficient, hydraulic treatment is needed to complete the well. Hydraulic treatment can be costly, and in some instances, possibly damage the production zone. In a unique modification of its field-tested and proven TUBING CONVEYED Perforating Technique, Vann Tool Company has devised what is believed to be a safe, effective means of perforating deep, high-pressure wells with abnormally high bottomhole temperatures. This method is called the VANNTAGE High Temperature TUBING CONVEYED Perforating System. It is now ready for field testing.

This paper presents an up-to-date evaluation of practices and problems encountered in the use of "small diameter completions."

As the result of a rapidly expanding backlog of experience and knowledge, more and more operators are viewing tubingless completions as a practical and entirely feasible means of completing wells.

The Sacatosa field is located in Maverick County, approximately 19 miles East of Eagle Pass, Texas. Production has been mainly limited to the San Miguel -1 reservoir. Conoco discovered this sandstone formation (1 135 to 1768 feet deep) in December 1956. Production wells were typically drilled using one string of 4 %-inch, J55, 9.5 lb./ft. casing. Completion practices typically did not always cement back to the surface. After many years of service, well casings have failed. It has been common practice to extend the productive life of these wells by cementing in 3-inch or 2 7/8-inch liners. However, 1.9- inch tubing is then required to run insert sucker rod pumps. Because of the thin wall thickness of this pipe, there have been numerous tubing failures. Additionally, approximately 10 years after running a liner, a well typically starts to have liner problems. A unique application of the progressing cavity pump (PCP) technology was tried in a pilot well by running this equipment without tubing. After the first success, three other installations were tried. This paper will discuss these installations and provide further discussion on the application of PCP technology to other wells.

The design and installation of a turnkey waterflood, the Yan-Kee (Canyon) Field waterflood, is presented.

It would be nice if elemental carbon and hydrogen could be burned and the entire heat of combustion could be obtained. But, handling raw elements is difficult, and hydrocarbons are by far the most available and convenient fuels. This means that the heat of formation of the hydrocarbon is lost. Fortunately, the heat of formation of fuel oils and natural gases is relatively small, e.g. 3 to 8 percent of the heat released. Combustion of hydrocarbons is complicated by the fact that the water produced may or may not be considered to be condensed. This is the difference between the higher (water condensed) and lower (water not condensed) heating values (HHV and LHV). In calculations of thermal efficiency, the heat obtained by condensing the water vapor may or may not be considered to be available. This is the difference between the gross (heat available) and net (heat not available) thermal efficiencies (GTE and NTE). The HHV and NTE are the more widely used terms, simply because they are higher values. These terms are used throughout this paper even though the respective bases are inconsistent. Figure 1 shows the NTE for burning natural gas (HHV of 1000 Btu/scf) in terms of the stack gas temperature and the excess air, which are the two parameters by which the performance of fired process equipment can be measured. The break in the curves at 100-130 F corresponds to the condensation of the water vapor produced during combustion. Above 135 F, the vapor pressure of water is greater than its partial pressure and condensation cannot occur. The NTE decreases with increasing stack gas temperature and the departure from linearity represents the change in the specific heat of the combustion gases with temperature. Below 135 F, the vapor pressure of the water vapor is less than the partial pressure and condensation occurs until it is essentially complete at 60 F. This corresponds to a GTE of 100 percent or a NTE of 111 percent. An efficiency over 100 percent means that heat is recovered which is not considered by the calculation procedure to be available. The decrease in the NTE with increasing excess air is the result of increased sensible heat losses in the stack gases. About 10 percent excess air is needed for complete combustion of the fuel. Any additional air acts as a diluent. It reduces the flame temperature and the heat-transfer rate in the firetube and increases the amount of stack gases. Methods for improving the NTE can be analyzed conveniently according to the function involved, that is, control of the excess air and recovery of more sensible heat from the stack gases.

The two piece plunger (a steel ball below and a hollow cylinder above) lifts liquids when the pieces are together and on reaching the surface the ball falls and the cylinder falls when a short shut-in period occurs. There are many instances where using this plunger results in production increases. However in some cases, it appears to have a lesser effect. Results of testing show that above certain rates, the components will not fall in the well. Test results, and the result of drag models to fit the test data are extended to show the potential user what the maximum allowable rates are from the well, before the individual components are predicted to be unable to fall in the well, thereby making application impossible without a temporary reduction in the flow rate. The results should allow the user to be able to better use the two piece plunger in a wider range of application conditions.

Two leases in a field in the Permian Basin contain dual wells that are being artificially lifted by different systems. The wells being lifted are dual completed wells producing from the Ellenburger and Fusselman formations at 8000 feet. Some of the wells on each lease are pumper with tandem rod pumps lifting both zones from 8000 feet. These wells are equipped with a tapered string of 2-7/8 in. O.D. and 2-3/8" O.D. tubing and a string of 1.315-in. O.D. tubing installed in 5-1/2 in. casing. The remaining wells on each lease are pumped with tandem, free type hydraulic pumps installed at 8000 feet. These installations utilize one string of 2-3/8 in. O.D. tubing and two strings of 1.315-in O.D. tubing installed in 5-1/2 in. casing. This paper will briefly describe these installations and present their operating characteristics and costs.

The paper will cover L.B.O.D.'s first two years of operating experience with a Power Water subsurface hydraulic pumping system. Included will be discussions of the physical systems, installation costs, operating costs, operating problems and approaches to eliminating these problems and reducing costs.

The Twofreds Delaware Sand Reservoir was discovered in 1957 and developed as a water-flood unit in 1963. By 1973, after a moderately successful waterflood, the production rate had declined to near economic limit. Carbon Dioxide injection for oil recovery was instigated in 1974, therefore, oil recovery since 1974 represents tertiary oil recovery after water-flooding. This paper discusses the actual application of CO2 injection procedures and the field performance for the 6-year period since CO2 injection was started. Performance to date appears successful in recovering additional oil from reservoirs of this type.

By 1960 a good majority of all producing wells on artificial lift in the United States will be on electric pump. Electrification of oil leases is increasing at a rapid rate for several reasons. All factors considered, it generally costs the operator less money to produce a barrel of oil by using electric power and equipment than it does by using gas engines.

For some time, the Petroleum Industry has recognized that fluids will experience "U-tubing" at some point during the placement in the wellbore. This "vacuum" effect has been especially noticeable during primary cementing operations, and it is largely attributed to the fact that the fluids used in cementing often are more dense than those originally in the wellbore. The phenomenon of the U-tube effect, although recognized, has never been fully understood. To better understand and predict this phenomenon, a mathematical algorithm has been developed to aid in analyzing fluid placement in the wellbore. It is based on a mass balance, an energy balance, a modified Bernoulli equation, and a full tracking routine to analyze fluid placement. Discussions encompassed in this paper will be to define the U-tube phenomenon, to evaluate its effects relating to cementing techniques, and to present an actual liner job in comparison to predictions made by this algorithm.

The final disposition of difficult-to-treat waste water, e.g., brines and of the residues resulting from the treatment and renovation of waste waters, e.g., sludges, is generally termed "ultimate disposal". The techniques of ultimate disposal include the treatment, handling, or placement of the waste in such a manner that it never comes in contact with human activities while in its noxious form. Solutions to the ultimate disposal problem include: (1) subsurface storage; (2) conversion of wastes to innocuous end products; (3) storage in lagoons and ponds, or spreading; (4) ocean disposal; and (5) conversion to useful products.

Artificial lift technology advancements typically are derived through either evolution or revolutionary means. When an irrefutable lift system benefit is chosen to be enhanced, it may require a revolutionary design concept to obtain the desired feature. This is the scenario that lead to the development of the. Rotaflex, an ultra long stroke pumping system we will refer to as the ULSPS. It is widely accepted that a long, slow stroke, big bore pump is the preferred pumping parameter of many experienced artificial lift technicians. The following will examine the benefits derived from the use of a ULSPS and address the concerns stemming from the utilization of such a product. The discussion will focus on operating cost and the impact on lease operating expenses (LOE). With the exception of labor cost, electrical expenses and maintenance repair costs account for a significant portion of the yearly operating budget. As both are controllable expenses, they offer the greatest potential impact when seeking cost reduction measures. Case histories that encompass years of gathering data by a major producer within the Permian Basin will be drawn upon for conclusions. Examination of failure frequency, comparative lift cost per barrel and other tangible features will be examined. The data will then be compared to other comparable lift systems within the same field.

Data collected over a three-year period on individually monitored wells has provided strong evidence to support the rationalization regarding ultra long stroke pumping systems (ULSPS"s). A total of thirteen ULSPS's are included in this study. Electrical costs per barrel and failure frequency will be compared to electrical submersible pump systems and conventional beam pumping systems. Additionally, another evolutionary product, in the form of a modified NEMA C motor, was installed on two of the test wells with the goal of further reducing KWh cost per barrel (one of the highest controllable expenses in artificial lift). Early field data on these motors will also be reported.

The Delaware sand is a common oil producing formation in the Permian Basin. It is a low permeability sandstone that requires proppant fracture treatments in order to be economically viable. Typically these treatments consist of crosslinked water based fluids with polymer loadings of approximately 30 pounds per one thousand gallons and carry from 25,000 to over 200,000 pounds of 20/40 mesh sand. This is a case history about one Delaware producer originally completed in November of 1992 with an initial fracture treatment similar in fashion to those described above, re-stimulated in November of 1996, but with a larger quantity of proppant and then subsequently temporarily abandoned in June of 2000. The details of a third propped fracture treatment, using an ultra-lightweight proppant at a fraction of the quantities previously used and the production response that resulted is the basis for this paper.

The flow of gaseous and liquid hydrocarbons is now routinely measured ultrasonically. Ultrasonics has taken some twenty years to prove itself in nonideal industrial petrochemical process control applications. It has now reached the stage where many users specify ultrasonics when they want to achieve reliable, accurate measurements without loss of pressure; linearity despite wide turndown ratios; no moving parts; wide temperature range; portability. The ultrasonic flowmeter output can in general be in units of velocity, volumetric or mass flowrate. This presentation covers basic contrapropagation theory; flow profile; flare gas molecular weight, density and mass flowrate determination; liquid clamp-on applications; and limitations of the technology.

Critical velocity in a producing gas well has been defined originally by Turner et al. as the gas velocity to carry small droplets of liquid upward. If you try to produce below the predicted value, the droplets are predicted to fall in the well and accumulate in the tubing and create liquid loading problems. Correlations such as Turner et at., Coleman et al, and results from Shell are compared. It is shown that at low pressures, projections for the required critical velocity differ the most. To provide some additional information on the situation, some low pressure laboratory measurements in 2 3/8's tubing are made and compared to the existing prediction methods. The reader will have a better idea of what accuracy is expected when trying to predict critical gas well velocity or production rate requirements from available correlations.

Over 40% of natural gas production in the United States over the next 20 to 25 years is projected to come from "Unconventional Gas" sources. These consist of coal beds, shales and low permeability sandstones and carbonates. Unconventional gas producers are as susceptible to wellbore damage as conventional. Scales, formation fill and organic deposits are probable. Therefore cleanout of these wellbores is as critical to maintaining production. The problem is that loss of fluid on these reservoirs during such an operation can shut-down totally the gas production. Presented is an overview of "Unconventional Gas" sources, potential wellbore problems, the challenges to removal and solutions to the problems.