As a joint effort by several petroleum industry associations in Texas, the Petroleum Industry Security Council (PISC) was formed in early 1982 to combat the ever mounting oilfield theft problem. Chartered as a non-profit organization, PISC is charged with developing programs designed to reduce and control thefts in the oil patch. The primary thrust of PISC is to support and compliment law enforcement officials and industry security personnel.

The word corrosion may be defined as the destruction of metal by chemical or electrochemical action. Destruction by mechanical means is usually called erosion. The rusting of iron is an example of corrosion, while the filing of iron to dust is an example of erosion. Essentially, atmospheric corrosion is the reverse process to that involved in refining metals from their ores. Iron is usually found in nature as iron oxide or iron hydroxide. When it corrodes in air, it returns to iron oxide or iron hydroxide. Copper occurs as the sulfide or basic sulfate. When copper tarnishes, it reverts to the sulfide, and, in certain atmospheres, to the basic sulfate. Because the refining of metal from ore requires the expenditure of energy, the metal is at a higher energy level than the ore, and it is natural that it would try to revert to the form in which it is found in nature. Because iron need only combine with oxygen to form the hydroxide, it is a wonder that we can use iron at all when it is exposed to air. The main reason that it does not destroy itself more quickly than it does is that rust, as it forms on the metal, acts as a barrier between the metal and air, thus slowing down the corrosion process.

The purpose of this paper is to provide practical information on the selection of natural gas compressors. No claim is made that this selection procedure is unique -- this information is drawn from experience and data from many sources. The intent was to keep the commercial aspect out of the paper and to try to provide a valuable source of information to be used by anyone. The paper will present practical design calculations used to size natural gas compressor packages for field application. The first part of the paper will be a combination of definitions and concepts that are involved in compression and the second part will concern itself with the sizing of the compressor package.

Thermal/infrared inspection detects and isolates abnormal variations in radiant energy emitted from bearings, motor, switch gear and transformers of operating oil field pumping units. Thus, qualitative and quantitative data on each problem is established. Thermographic and/or photographic images are taken to document the condition.

Thermographic inspection, through the use of portable infrared imagers and non-contact spot radiometers, has been performed on approximately three thousand pumping units in many active Permian Basin oil fields within the past two and one-half years. Infrared imagers with camera adaptability were used to inspect saddle or Sampson post bearings, equalizer or tail bearings, wrist pin bearings, exterior gear box bearings, electric motor and related switch gear on each beam-type pumping unit. In many instances, pole-mounted transformers were scanned for thermal differentials, completing the wellsite inspection. This technique detects and isolates abnormal variations in the radiant energy emitted from the bearings, motor, switch gear and transformers. Thus, qualitative and quantitative data on each problem bearing or electrical component was precisely established. Thermograms and photographs were taken to document the condition.

This paper will present case studies detailing the successful use of thermoplastic lined tubulars including liner products composed of HDPE, a proprietary polyolefin blend, and PPS of 2,400 wells operating in 29 different fields. All of the lined tubulars in these wells are still in services today and some were installed back in 1996. A review of critical limitations of the liners such as temperature and diameter changes will also be discussed in an effort to avoid the misapplication of thermoplastic liners. Improved tubular service life, economic benefits, and enhanced flow characteristics due to the high quality service finish of the liners will be detailed in at least twenty specific case histories and field including both injection and production well environments.
The fundamental technical benefits of various thermoplastic lined tubulars will be covered with an emphasis on the proven extension of tubing service life using thermoplastic liners. One often overlooked advantage of TPPL tubing is that is reduces the friction of sucker rods on the tubing ID. Data from recent testing by ConocoPhillips that quantifies the benefit will be presented. Furthermore, to exhibit the overall economic impact of thermoplastic lined tubulars, a review of field installation and handling procedures will be presented as well.

This paper discusses the installation and field service application of thermoplastic pipe with reference to basic physical and chemical properties and pipeline design considerations.

An innovative approach has been used to model flow through discrete fracture networks in a massive carbonate reservoir in order to understand and predict performance of vertical and horizontal well completions. This approach focuses on completion effectiveness and the influences that fractures have in a three-phase gravity influenced flow system. The model is set up as a dual porosity, dual permeability simulation of a discrete fracture network of high permeability grid blocks capable of modeling three-phase flow. This model reveals the dominant factors controlling well life cycle performance demonstrated in the Yates Field Unit Natural fracture networks dominate flow throughout the reservoir with added economic significance to completion efficiency. Therefore 3D discrete fracture network (DFN) models based on connected-fracture orientation from FMI logs and flow surveys have been used as a basis for constructing the 3-phase simulation grid. The differences in mobility between the three phases result in abnormally shaped gas-oil and water-oil contacts as drawdown is applied. As the fracture oil column depletes, oil mobility reduces with the decrease in effective fracture connection to the outlying oil column. This loss of oil mobility through phase dis-connection in flow conduits has not been the focus of prior studies. The simulator has successfully generated production profiles similar to those observed in field performance data. This wellbore simulation has been used to develop a strategy for optimal completion performance and placement.

Borehole sonic transit time measurements have been used by engineers and geologists in west Texas since the mid-1950's. The great majority of this sonic data has been acquired in open hole. With recent improvements in acquisition and processing technology, reasonable data can now be obtained in cased wellbores. The purpose of this study is to compare cased hole data with the established open hole data standard. The evidence suggests that usable compressional and shear transit time data can be obtained through casing. There are over 120,000 cased wellbores in west Texas as of this writing. A large percentage of these were surveyed prior to the development of most current petrophysical and geophysical processing techniques that require sonic inputs. With this technology, these wellbores can now be properly evaluated.

Past studies by DOE, NPC, and GRI confirm that an enormous volume of gas is trapped in low permeability reservoirs. However, neither current technology nor price is adequate to allow widespread development of these reservoirs. To better understand the fracturing process and, thus, be able to eventually improve technology, it is first necessary to improve our understanding of the low permeability reservoirs that are being fracture treated. The Gas Research Institute (GRI) is sponsoring research in which comprehensive efforts are being undertaken to perform geological, coring, logging, well testing, fracture treatment monitoring, and fracture diagnostic studies on selected wells in two targeted basins, the Travis Peak formation in East Texas and the Corcoran and Cozette formations of the Piceance Basin. This paper summarizes the research effort which has as its ultimate goal to learn how to measure and analyze data so that fracture dimensions can be calculated in real time, or as the fracture treatment is being pumped. Eventually, we hope to be able to alter the design during a treatment in order to control fracture shape. Engineers and scientists are being placed in the field with computers so they can analyze the data while the job is being pumped. Several cooperative wells in East Texas have been drilled and analyzed. Additionally, the first of four Staged Field Experiments has been completed. The Staged Field Experiments are wells drilled where GRI is in complete control of the entire operation allowing more latitude with experimentation not possible in cooperative wells. Conventional whole cores (up to 400 feet per well) have been taken. The cores have been used to determine regional and local environments of depositions. Complete suites of open hole logs have been run and used to calculate rock and mechanical properties. Log interpretation results have been found to compare favorably with the core analysis results. In-situ stress tests have been run and compared to the log and core data. Fracture treatments are being monitored and analyzed. Post-fracture well tests are run to estimate the effectiveness of the fracture treatments. Also included in the paper is a documentation of the monitoring equipment that has been designed and developed by GRI contractors. Included are mobile Qualit Control (QC) laboratories and a new generation rheology unit that measures both couette and capillary viscosity at bottomhole temperatures. The unit also is designed such that fluid leakoff anticipated in the formation can be simulated.

More than 400,000 wells in the United States operate with beam pump artificial lift equipment. Most of these wells have a pump capacity which exceeds the production rate of the well. Also, most of these wells pump 24 hours per day. These wells would operate more efficiently and at a lower cost with a device that reduces the amount of pumping unit operating time. This reduction in operating time decreases both
electricity and maintenance costs.

Computers aid the engineer in that they make available sophisticated solution procedures, take the drudgery out of computation and provide accuracy in number handling. One of the most recent innovations in computing is the timesharing system. This system brings the computer face-to-face with the engineer and gives immediate online answers, but is this tool a panacea or a Pandora box, a money maker or a dollar drain; severely limited or unlimited; to be welcomed or resisted? The authors will relate their experience discussing suitable and unsuitable timesharing applications, those programs currently available and those known to be under development, and will show basic timesharing costs together with the economics compared to other computing methods. A basis is presented for placing a dollar value on the shorter "turn-around" time obtained by timesharing.

This article examines some causes of rod failure and explains material selection, running and pulling practices.

Producing hydrocarbons from the lower Delaware Formation in SE New Mexico and West Texas is often associated with a high water production. In the Matthews Field in West Texas, an operator was encountering water production of over 600 bbls per day from the prior treated wells. Modifying the stimulation techniques and processes were chosen in an attempt to improve the production results. Multiple stage treatments using coiled tubing with selective placement controls and reduced rates were performed to lower the fracture height growth in an attempt to reduce water production. This method included using conventional fracturing fluids, specialized coiled tubing perforating and controlled fracturing placement, and a relative permeability modifier capable of modifying the relative permeability by coating the formation rock, thereby reducing the potential for water production. This paper will detail how these operations were performed.

The main purpose in the treatment of the Devonian formation is to successfully place the proppant strategically to produce as little non-hydrocarbon fluid as possible. In the Roepke Field in West Texas (Crane County), an operator was entering his first newly drilled well in the area. Difficulties in the completion for an offset operator included high treating pressures resulting in shortened pump schedules and low fracture conductivity. Issues for this operator included proper log analysis, perforating schemes, well-bore mechanics, and the main stimulation treatment design. After discussions with the service company, an alternative method of fracture treatment was successfully tried and adopted to solve these problems. This method included designing the treatment with calculated rock properties in a 3-D fracturing model pumping a high permeability regain fracturing fluid via tubing, which doubled as a temporary production string. This paper will detail how this problem was successfully addressed.

The paper will discuss an innovative stimulation technique performed on several open hole horizontal San Andres wells in Dawson and Gaines County, TX. Stimulation objectives will be outlined and explained along with supporting well production information. The paper will also compare this completion technique with several other horizontal stimulation techniques performed in the recent history of this field.

Understanding the fundamental advantages and disadvantages for running a Top Hold Down Pump compared to the advantages and disadvantages of running a Bottom Hold Down Pump.What type of well conditions and parameters to consider when deciding on a Top Hold Down Pump or Bottom Hold Down Pump.

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Augue, in eu scelerisque diam a turpis eu ultricies in ut. Ut rhoncus etiam, porttitor, porta lundium, adipiscing lorem tristique amet, pulvinar magna, eros. Aliquet pid augue dolor eu vel nunc natoque, montes urna eros, mus tristique sociis, integer tortor! Rhoncus, integer augue parturient augue mattis aliquam! Magnis et quis diam mattis duis purus ac rhoncus nascetur ridiculus turpis, lorem porttitor lacus eu montes odio eros, nunc cum in, et nisi ultricies, parturient, tristique ut, turpis cursus. Tempor! Massa pulvinar. Porta ac porttitor? Magna! Pid magna. Purus, aenean lundium augue vel ac mauris porttitor dapibus enim integer augue pulvinar, augue placerat, lorem natoque amet porttitor lacus scelerisque, sed lectus mauris magna lorem sed, rhoncus integer ac? Aliquet, ac sed.

A computer program has been developed which permits torque calculations in a much simpler and much accurate manner than previously presented in API publications. This is accomplished by using a highly accurate digitizing technique to input the necessary number of points from the dynamometer card. The proposed technique improves the accuracy of the data over manual input and allows a much greater number of points to be used for subsequent analysis. The program can handle all pumping unit geometries and calculates all the parameters for a complete analysis of the pumping unit: PRHP, PPRL, MPRL, PT, etc. The instantaneous torques are plotted vs. crank angle. The program also evaluates the counterbalancing of the unit by calculating the Cyclic Load Factor for actual conditions. The author proposes a new technique to find the maximum counterbalance moment needed for ideal counterbalancing. The theoretically sound procedure seeks that counterbalance moment which results in the least value conditions. of Cyclic Load Factor for the given This approach ensures the minimum of prime mover power requirements, installations, and can reduce the power consumption of existing thus improving the economy of sucker rod pumping.

Manufacturers are constantly being asked to furnish special combinations of stroke length, beam sizes and other structural modifications to meet the particular requirements of those responsible for the application of pumping units. These special demands are often made without due consideration of their effect on the loading of the unit gear reducer and prime mover. Torque factors which were made available through the workings of API committees have not been used as much as they should be; if they were, some of the special arrangements would not be requested. The proper use of would make it evident that such changes could easily overload the gear reducers. Although the use of torque factors was started approximately 15 years ago, their general adoption has been slow. Producers have not demanded and manufacturers have not furnished them because of the trouble in calculating them.

In order to clarify the present discussion, it is thought wise to review briefly the discussion and demonstration of The dynagraph animator, to help you visualize the properties of sucker rods, and the significance of the dynagraph. The dynagraph of an oil well is no more than a graphical record of force recorded against a distance from some starting point. We usually consider the lowest point in the polished rod travel, which is the beginning of the point. The dynamometer is usually supplied with a vibrating device whereby the time element be separately recorded with respect to the starting point.

The Oil and Gas Industry is benefiting from development and use of improved predictive computer programs that now utilize several friction defaults. These predictive programs are more capable of predicting surface and downhole rod pumping conditions. The need for improved predictive accuracy is requiring program users to adopt improved estimates of downstroke friction to model downhole pumping conditions. Lack of improved estimates of downstroke friction has resulted in program users accepting and designing with current friction defaults that may result in results different than actual downhole pumping conditions. This paper develops a method of estimating total downstroke friction from existing dynamometer analysis. Use of this method in producing fields with similar operating conditions will provide improved estimates of total downstroke friction. A better understanding of the magnitude of total downstroke friction will result in improved friction defaults. Improved friction defaults will result in more effective designs of rodstrings and artificial lift systems.

Given the dynamic nature of production for an oil well and the magnitude of the lifting cost, there are few opportunities with a better payoff than reviewing the total rod system designi-2. However, with the current trend of increased well count and responsibility for the engineer and field personnel, it is often one of the things for which there is never enough time. Even with a shelf full of technical manuals, books, forms, and programs to calculate everything from pumping unit and rod loads to sheave and belt sizing, designing all of the components of the rod system is a very time-consuming operation. " TOTAL ROD " system design is a LOTUS 123 n based template for efficient rod system design and management. It allows numerous combinations of all operating conditions to be considered simultaneously in one program. Calculations are performed for: API RP 11L loads s for Conventional, Mark II, Air Balance, and C M I units based on conventional RPllL tables (or based on tables generated by the wave equation model 4 of Shell Oil Company), sinker bars, producing and static bottom hole pressures based on fluid levels 5 corrected for gas in fluid or foam, production capacity based on producing and static pressures and reservoir drive, belt and sheave sizes, daily pump time, electrical cost, mud anchor and gas anchor sizes and placement, and total system efficiency. "TOTAL ROD" allows multiple runs to be considered in detail and in a fraction of the time. The spreadsheet format of LOTUS 123 presents the runs side by side and provides graphics and data management capabilities.

This paper presents the results of a Total System Cost Comparison program between Electric Submersible Pump's (ESP"s) and Beam Lift Pumps that are typical within Amoco's northern Permian Basin operating areas. This program calculates a common variable of, .VBFPD. for Total System Cost and Operating and Maintenance Cost. This common variable may be used to help the operator make the best decision regarding economics, on which type lift to use. The calculation takes into account all equipment cost, all installation cost. all repair cost and all operating cost for a typical 10 year period of time at a specified depth and volume. Also considered in calculating the repair cost for a 10 year period of time is the type failures, cost per type failure and frequency of these failures that are typical within these operating areas.