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.

This paper presents two field case histories from multiyear horizontal completion projects in west Texas that were very successful at exposing the "false economy" of not cementing casing in horizontal wells drilled in low-permeability reservoirs. Moderate increases of 20 to 25% in initial well costs yielded a 3- to 10-fold increase in discounted cash flow through improved hydrocarbon recoveries. Case histories are developed for adjoining wells with similar reservoir characteristics and differing completion techniques. Comparisons of single lateral cemented liner completions to openhole completions and uncemented liner completions will also be presented.

Problems related to paraffin and asphaitenes continue to plague the oil and gas Industry. These include solid deposits, stabilization of emulsions and sludge production"'. Common solvents and condensates are popular treatments for dissolving and/or controlling paraffin and asphaltene related problems. Typically, these fluids have been used with little regard for long term effectiveness and formation damage consequences. Unique condensate feedstocks with high multiple aromatic content were identified. Laboratory testing, blending and refining resulted in solvents that can keep paraffin and asphaitenes in solution under a wide range of conditions. As a result of this work condensates are blended and refined to maximize solvency, demulsifying properties and maintain wettability without the addition of chemical additives. The properties of these refined natural solvents offer economical alternatives and/or enhancement to common treatment practices including hot oiling, condensate treatments, chemical treatments, stimulation and production treatments.

The Unit Operating Agreement is the contract among unit working interest owners which controls their respective functions in unitized operations. While the provisions of the operating agreement related to field wide units are generally acceptable to non-operators, there are, however, some areas of concern. The purpose of this paper is to briefly discuss some of those problem provisions.

Recognizing and cost effectively eliminating liquid loading in natural gas wells through the use of low pressure wellhead compression. The use of compression to eliminate liquid loading can be utilized in conjunction with other production methods such as soaping, siphon strings, plunger lift and beam pumping. Desireable features of low pressure natural gas compression will be highlighted with actual field cases illustrating the equipment characteristics needed for successful de-liquification of natural gas wells. Through computer analysis of pressure and area flow rate analysis, along with field testing and continued montitoring, the changing of compressor clearances, in conjunction with control valves, can be optimized to successfully keep gas wells unloaded during a longer period of time without resizing and replacing the compressor. Thus far the proper sizing and utilization of low pressure wellhead compression has enabled operators to maintain higher producing rates and velocities to keep gas wells unloaded which increases the monthly cash flow to the producer and extends the economic life of properties which leads to the recovery of increased incremental reserves.

The Variable Slippage Pump

More and more interest is generated for fiberglass tubulars because of their excellent corrosion resistance and mechanical strength. The major obstacle for more extensive use of fiberglass has been the lack of recognized engineering standards that would allow the field engineer to specify fiberglass with confidence for a particular application. Recognizing this need, several API committees are at work with unusual speed and efficiency to develop product specifications for fiberglass tubulars. Specifications for low-pressure line pipe were issued in 1986. Specifications for high-pressure line pipe followed in 1988. A specification for fiberglass downhole tubing is expected to be issued next year, in 1991. Finally, a specification for fiberglass casing is planned to be issued in 1992. This paper summarizes these API activities and details API fiberglass product specifications, both those issued and those still in committee.

More and more interest is generated for fiberglass tubulars because of their excellent corrosion resistance and mechanical strength. The major obstacle for more extensive use of fiberglass has been the lack of recognized engineering standards that would allow the field engineer to specify fiberglass with confidence for a particular application. Recognizing this need, several API committees are at work with unusual speed and efficiency to develop product specifications for fiberglass tubulars. Specifications for low pressure line pipe were issued in 1986. Specifications for high pressure line pipe followed in 1988. A specification for fiberglass downhole tubing is expected to be issued next year, in 1990. Finally, a specification for fiberglass casing is planned to be issued in 1991. This paper summarizes these API activities and details API fiberglass product specifications, both those issued and those still in committee.