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.

Two techniques have been applied to exploratory well air drilling operations. These include air coring and operating the Dynadrill with air. The purpose is to maintain the ability to air drill below cored intervals and/or after making directional corrections or whipstock operations. Application of these techniques has allowed drilling the remaining footage of hole with air, at an increased penetration rate when compared with fluid, and thus reduce overall well cost. This paper presents the operating conditions and techniques used for air coring and operation of the Dynadrill based on actual well air and air-mist operations, are reviewed to established guidelines for equipment requirements and equipment performance.

The MSDU 1 (Mary Scharbauer Devonian Unit No. 1) was completed in December 1998. It was Mobil Drilling Midland's first attempt to drill a horizontal lateral while underbalanced. The Mary Scharbauer experience provided valuable data on the benefits and drawbacks of UBD (Underbalanced Drilling) in the extended reach environment. Increasing ROP in order to reduce cost was the primary goal of the MSDUl project. Increases in ROP from UBD were apparent when optimal bottom hole pressure was achieved. Maintaining optimal bottom hole pressure was impossible do to the limitations of conventional MWD (Measurement While Drilling) equipment. Extensive drill stem deterioration caused project costs to skyrocket and placed any future UBD projects on hold until a solution to the problem could be developed. Investigation of the drill stem corrosion showed that the most severe pitting occurred on the drill pipe in the lateral section of the well. Analysis of the drill fluid as well as formation fluids showed that the most reasonable explanation for the deep pitting observed on the drill pipe was "Oxygen Erosion Corrosion." Oxygen erosion corrosion was then simulated in the laboratory in an apparatus that produced conditions like those found in the lateral section of the MSDUl well. Many corrosion tests were completed in an effort to find inhibitors that would function in a deep, hot, oxygenated, and abrasive well bore environment like that of the MSDUl well. While this was being done 99.9+ % oxygen free UBD methods were evaluated. Eventually a corrosion inhibition system that worked under conditions like those of the MSDUl was located and proven on Mobil Midland's second UBD extended reach well the PFU 23-24 (Parks Field Unit 23-24). Conventional MWD equipment required that the drill pipe be loaded with water in order to generate a readable mud pulse. When surveys were needed underbalanced conditions were eliminated and ROP on the MSDUl dropped from 26ft/hr to 8ft/hr. Optimum underbalanced conditions were recovered after the well bore could be re-gasified. It was estimated that using a MWD system that did not require the drill pipe to be loaded would cut the cost of drilling a MSDUl like lateral by $60,000. Midland Drilling located an EM MWD (Electromagnetic Measurement While Drilling) company that stated their equipment would work for drilling a Devonian lateral underbalanced. When the equipment was evaluated on the PFU 23-24 it performed acceptably but learning were documented that will improve future operations. Mobil Drilling Midland continues to develop technology to improve bottom line profitability. Currently work is being done to determine the feasibility of drilling extended reach horizontal laterals with air compressors and a water/foam drilling fluid. If feasible this method will be half as expensive as our current lowest cost UBD option. The drilling curve will continually shift to the left as key learnings are implemented on fume projects.

Construction design and operating procedures for underground injection of brine waters are receiving more attention as the industry progresses toward full implementation of the provisions of the EPA Underground Injection Control regulations. Specific problems common to most injection well design and operation are discussed including casing and cementing programs, injectivity testing and reservoir performance calculations. Special emphasis is placed upon limiting surface injection pressures to avoid such hazards as invasion of potable water reservoirs.

This paper is presented as a reference for drilling. washing and completion of storage wells in the Salado Salt Section of the Eastern New Mexico-West Texas Area. The discussion and recommendations expressed herein are based on the experiences and problems encountered by the El Paso Natural Gas Products Company in its operation of the Odessa complex LPG storage wells.

Gas interference continues to be one of the major operating problems in pumping wells. In order to combat this problem effectively, we need a better understanding of what the pump volumetric efficiency should be under various well subsurface conditions Once we know how the pump should perform, it will be possible to select the best setting depth and determine whether a gas anchor is needed. Care must be used in the selection and in the installation of gas anchors, otherwise the results will be disappointing. If free gas is present, not only must an effective gas anchor be used but also must the pump develop a high compression ratio Thus, the type and design pump used is critical. Pumping wells from under a packer and small diameter casing completions are two practices that have increased the gas interference problem. Pump efficiencies and production can often be improved in such type wells.

As the cost of maintenance of gas transmission lines and plant maintenance at gas gathering sites has increased, the detection and control of 02, H2S, and CO, has become an important issue in cost controls and safety. Even though the actual costs related to the presence of these elements isn"t known exactly, the cost per location is estimated to be in the millions of dollars annually. The corrosion-related cost to the transmission pipeline industries is estimated to be between $5 billion and $8 billion annually. Obviously, all of these costs can"t be attributed to of 02, H2S, and CO,, but these three elements are a large contributing factor to these costs. In some gas high levels of CO, is present; therefore the removal of this element to meet the 4% contractual requirement is necessary thus contributing to the cost. In addition, CO, is an acid gas that contributes to the corrosion problem. The safety of transmission lines has a far-reaching affect including life, property damage, and large monetary liabilities for the transmission companies involved. Early detection and preventing the corrosion of these transmission lines, which in turn, prevents pipeline explosions, is extremely important. These elements accelerate the corrosion on all carbon steel components including the pipeline systems and components in plants. It is true that most of the carbon steel systems are protected with corrosion inhibitors, but large quantities of oxygen cause the inhibitors to have a limited amount of protection. It has been determined that oxygen levels of 10 PPM or less will have very little affect on these inhibitors. The identification of sources of oxygen and the recognition of hydrogen sulfide and carbon dioxide present in natural gas has become very important to corrosion prevention programs. The cost of this identification and elimination of the sources is far less than the cost of the repair and the liabilities of the corrosive affects if left unattended.

As CO2 miscible flooding becomes commonplace in our industry, more and more emphasis is given to gas dehydration and corrosion control in CO2 handling systems. This paper deals with the design of CO2/methane dehydration facilities, related metallurgical considerations, and the sizing of contact towers and reboilers to meet the varying CO2 concentration expectancies.

Artificial neural networks (ANN) are computer programs designed to mimic the functioning of the human brain. ANNs can be designed to "learn" by reviewing a data set consisting of a set of known inputs and a corresponding set of desired outputs. Once an ANN has been trained, it can predict outputs given just the set of known inputs. While the applications are broad reaching, one valuable application of such tools is in petroleum exploration. In places where both exploration data (such as log, core or geophysical data) and production data are available, a network can be designed and trained and used to predict production given a similar suite of exploration data. This work will discuss design issues in exploration neural networks, explore available software and review two case studies where neural networks were used to predict total production for undrilled sites in two formations in the Permian Basin.

Recent inflation has caused many in the industry to try and develop methods to improve the efficiency of their well repair programs. BP America, in cooperation with Key Energy, has begun a pilot program in SENM that couples existing KeyView data with a basic root cause perspective to deepen the understanding of service rig delays. This paper will discuss in general terms, the capability of the KeyView data capturing system, and in specific terms, how the available data was adapted to challenge assumptions about service rig delay times.

Gas lift is a flexible and forgiving form of artificial lift. Gas lift is so flexible that many installations for offshore platform wells are designed and the retrievable gas lift valve mandrels are installed during initial well completion. Efficient gas lift operations can be anticipated from installation designs based on limited well performance data by avoiding excessive distance between valve depths. The daily production rate from most gas lift installations depends upon the well deliverability and the available injection gas pressure and rate. The gas lift designs and systems described in this paper are not typical installations that are discussed in gas lift textbooks. The design concepts are not original and most of the information has been published in years past. The same innovative ideas reappear in cycles and will seem new to the engineer who has recently entered the petroleum industry. This paper brings together the description of several unusual gas lift applications into a single publication. Hopefully, one of these special installation designs will be a solution to a present artificial lift problem. Modification of an installation design tailored to a particular well or field is left to the reader.

It is the purpose of this paper to discuss several chamber gas lift installations in which the chamber operation produced more fluid than anticipated. Several unusual installations are reviewed.

Increasing wellbore complexity and increasing pressure to improve drilling economics has necessitated increased focus on preventing lost circulation. This has required a close focus on wellbore stability and improvements in wellbore strength such that losses are minimized or alternately casing strings may be eliminated. In addition the drilling of depleted zones in the same section as normally pressured formations has led to increased focus on maintaining wellbore integrity and minimizing losses. The development and engineering of unique drilling fluid additives which can aid in increasing wellbore stability and minimizing fluid losses into drilling induced fractures has been a key in achieving the desired operational goals. The Authors will discuss the design of these unique drilling fluid additives and the treatment techniques required to ensure optimal wellbore stability and minimal induced fracture losses, along with the engineering tricks required to ensure successful application of such treatments.