The Petrovalve technology eliminates the high failure rate and low efficiency inherent to the traditional ball and seat valve configuration which has been in use for the last 70 years. These improvements are due to the guided seating surfaces of the Petrovalve design, providing some exciting opportunities for producing oil companies through both material selection and operating variables. With a larger flow area and less pressure drop across the valve, the Petrovalve design allows for increased pump efficiency. Production increases of 35% are not uncommon in the field. Eliminating gas lock problems common to many thermal and non-thermal well pumping operations is the Petrovalve Gas Breaker. The traveling valve automatically opens at the end of each cycle allowing the hydrostatic fluid to flow through and exchange any trapped gas accumulations. Available in cast cobalt alloy (stellite), tungsten carbide, and titanium carbide, the whole line of Petrovalve products offers increased production and decreased maintenance costs and downtime. Through greater pump efficiency and the versatility to operate at deviated angles, right through to the horizontal, oil producers see a direct effect on the bottom line.

The Progressive Cavity Pump (PCP) has been used in down-hole applications for over fifteen (15) years and has progressed from only one model and one elastomer to over twenty models and several different elastomers. The depth range for the rod driven pump system has increased from 1000" to 6000" and even a few 8000" applications. These applications call for special elastomers and considerations as to the fit and/or design of the pump and the system. Down-hole pump displacements have increased from 5 to over 1000 bpd/l00 t-pm. The resultant torsional requirements for the large pump designs have reached the limits of conventional sucker rods, therefore, new methods for rotating and transmitting torque to the pump are being conceptualized, designed and tested. New developments, in the past two to three years, that will be covered in the following text consist of elastomers; rotor coatings; drive systems; rod centralizers; and rod-less systems as well as new applications where PCP's are being utilized, i.e. high temperature, CO2 and H2S.

The future of an oil or gas well is dependent on its early life. One of the things occurring in a well's early life which affects its future is cementing the well. Proper application of cement ensures good zone isolation and protection of casing. Good zone isolation is necessary to ensure that the stimulation treatment is applied only to the zone of interest and to limit production of undesirable well fluids.

The ability to estimate descriptive engineering parameters, such as permeability, and to generate production forecasts and reserves based on those parameters, without the cost of fir11 numerical simulation or extended buildup tests, is provided by the Reciprocal Productivity Index graphical production analysis method. The method's theoretical basis arises corn the fact that traditional constant rate or constant pressure (potential) boundary conditions are sufficient, but that the necessary boundary condition only requires that the sandface transmissibility remain constant over time. With that difference, it is possible to accurately evaluate production histories, in which both the rate and pressure are varying over time, using traditional well testing methods. Examples for both oil and gas wells demonstrate the interpretive capability and limitations.

Fluid injection into the Permian carbonate rocks of West Texas has generated millions of barrels of additional reserves in recent years. Sufficient performance history is now available so that certain general conclusions may be drawn and guidelines set for future project installation. The fundamental precept for evaluating these reservoirs for fluid injection is a detailed knowledge of their geology. Permian carbonante reservoirs can be characterized by the dominant trapping mechanism into three distinct types. Different performance histories may be anticipated for each type. Reasonable predictive procedures may also be developed.

The petroleum industry today is faced with an acute shortage of technical personnel. If this trend continues, the industry will suffer economically as well as technologically. The United States" petroleum industry has always been a leader in the world in technological achievements and in all facets of oil and gas drilling and production techniques. Oil, gas and service company personnel have traveled the world over aiding many countries in their oil and gas development. Without this technological aid of engineers and service company personnel, our nation and many other countries would not have advanced as rapidly in the industrialized world we live in. This paper is directed toward a major problem which faces the petroleum industry, this being a shortage of technical people to supply this industries critical need.

The internal protection of pipe through the use of plastic coatings applied by "in place" methods has enjoyed a rising acceptance in the oil and gas industry during the past four years. This growth was witnessed in 1958 as compared to all preceding years, not only by a larger dollar value of sales. But also by a larger average job contract; a wider variety of reasons which lead the individual user to select "in place" methods; and by an actual greater number of users. This rising acceptance of "in place" work has been predicated upon the contractor's ability to improve his cleaning and coating techniques. The present day "in place" cleaning method, which relies not only upon mechanical scraping but also upon chemical reagents and solvents, results in a surface comparable to any surface cleaned industrially, as in automotive or appliance plants.

The Salt Creek Field Unit is located in Kent County, Texas, 70 miles southeast of Lubbock. Mobil E & P U. S. is operator of the waterflood, CO2 flood, a CO2 separation and re-injection plant, and a NGL recovery plant. CO2 injection began October 26, 1993, into the 57 pattern Phase I area. Oil production has increased from 18,500 BOPD in October, 1993 to 29,500 BOPD in November 1994. This paper is a status report of the CO2 operations to date.

The purpose of this paper is to select a normal deep well and to design combinations of tubing strings. In many wells today, the design of tubing strings is not based simply on the function of tension, collapse and burst of available API tubes. Corrosion has been an oilfield problem almost from the beginning of the industry. High field pressures and deeper wells have added a whole new list of words to the oilfield vocabulary, particularly when referring to tubing; words such as stress corrosion cracking, hydrogen embrittlement and so on.

This paper discusses the selection, fabrication and application of flexible thermoplastic materials that provide impervious liners in oil-field tanks. Installations in steel-bolted, steel welded and other types of tanks are considered. Protection from mechanical damage, pipe connection sealing, inspection and testing are discussed. In addition both successful and unsuccessful case histories are presented.

Since the inception of the rod pump it has been assumed that all rod pumps must lift fluid. For centuries that has been true. In modern times leathers and flapper valves have been replaced with spray-metal plungers and balls and seats, metal barrels have replaced bamboo and wooden sucker-rods are now made of metal, but the concept and primary design has stayed the same. Many advances in metallurgy and precision manufacturing have extended pump runs, but for the most part oil producers today are using the same technology their grandfathers used on the ranch to water their cattle with windmills. There is a new technology so disruptive and unique the US government has granted a patent. Open your mind, remove your prejudices, and get ready to start thinking upside down. You are about to enter the world of the Skillman Downstroke Pump.

This paper describes the performance of both a pilot and a Unit-wide carbon dioxide (CO2) flood in the Slaughter Estate Unit, Slaughter Field, Hockley County, Texas. The performance and design of both projects are compared and contrasted. The comparison yields insight into the process, the impact of flood design variables, and the effects of project scale. Between 1976 and 1984, Amoco Production Company conducted a pilot flood consisting of a double five-spot pattern of twelve acres in the Slaughter Estate Unit. A stream of CO2 and hydrogen (H2S) sulfide gas was injected using an alternating gas water injection ratio of 1:1 followed by chase gas. A 65% hydrocarbon pore volume (HCPV) slug of gas was ultimately injected. The pilot project has been the topic of several SPE papers. This paper summarizes the performance to provide a basis for comparison with the performance of the Unit-wide project. The pilot performance was extremely encouraging and supported a recommendation to implement a field scale flood in the Unit. In 1982, Amoco approved a project to start up a Unit-wide CO flood and injection began in late 1984. The original design of the Unit-wide flood involved injecting a 30% HCPV slug of pure CO2 using a 2:1 gas alternating water injection ratio. In response to changing 011 prices, the gas-water injection ratio and slug size have been modified to maximize the profitability of the project. The resultant gas-water injection ratio scheme is also expected to improve vertical sweep and reduce gas handling requirements. The Unit-wide project has responded very favorably to the injection of C02.

The need for a radioactive waste repository is not predicated upon public acceptance of nuclear power: the need already exists. Wastes from the chemical processes associated with plutonium production have been accumulating within the AEC/ERDA complex since World War II. The nuclear power reactor fuel cycle is plugged with 2000 metric tons of spent fuel awaiting reprocessing, and the backlog is growing rapidly. Clearly, there will be a radioactive waste repository; the only questions to be answered are where and how big it

The statistical analyses of wireline logging data can be used as a guideline to predict the reservoir performance of the Permian and Pennsylvanian sandstone reservoirs in the Val Verde Basin of Southwest Texas. This study shows that the higher the statistical deviation of the logging data associated with the sand, the lower and the more erratic the natural gas production.

The current statutory depletion allowance of 27.5% of gross sales is and has been the subject of much controversy. Critics claim the 27.5% figure is unjustifiably high and should be reduced. However, in practice, with few exceptions, the actual allowable depletion for oil producing properties is less than 27.5% of gross sales due to the provision that allowable depletion cannot exceed 50% of net income. The actual depletion allowance realized depends upon a variety of factors or conditions. This paper reviews the effect of assumed conditions upon allowable depletion for four hypothetical cases involving oil producing properties. The conditions investigated include various development densities and corresponding prorated top allowable rates for a given lease, adverse factors of high operating costs and a low crude price, varying reserves for a well with a fixed top allowable rate, and varying top allowable rates for a well with a fixed ultimate recovery. In all cases the allowable depletion was found to be considerably less than the 27.5% statutory depletion allowance.

Any procedure used to increase the flow of fluids from a well can be called a stimulation treatment. In general, such treatments fall into two broad categories: first, those performed as a part of normal well completion and second, remedial treatments designed to boost declining production of older wells. The principal stimulation methods are (1) nitro blasting, (2) perforating, (3) acidizing, (4) fracturing, and (5) formation-cleaner treatments.

The reliability of tuning and sucker rods is critical to the successful long-term production of a well. Corrosion, erosion-corrosion and mechanical wear can significantly reduce the life of tubing and sucker rods.
Internal Plastic Coatings (IPC) technology has evolved over the past 75 years and recent advancements in material have significant increased the abrasion resistance of the coatings for Oil Country Tubular Goods (OCTG). Historically there have been concerns regarding the coatings ability to protect against wear from mechanical interventions and artificial lift involving the use of wireline, coiled tubing, sucker rods and plungers.
This paper will highlight these recent advancements in technology and include field case histories where the use of abrasion resistant coatings have been successfully utilized in artificial lift applications, including rod pumping wells and plunger lift wells.

This paper discusses the theoretical advantages of ultra high sand concentrations (UHSC) in hydraulic fracturing treatments. Results from several treatments are presented. For comparative purposes, results from conventional, lower sand concentration treatments are presented. Mechanical aspects of handling ultra high concentrations of sand (10 lb/gal and greater) at injection rates from 40 to 70 BPM have been a major consideration in conducting these treatments. Sand concentrations, at these rates, have been unattainable in the past partially due to sand handling problems. The capability of handling sand under these conditions has been developed and is discussed.

This paper will present a summary of jet pump theory and performance, and an algorithm for applying jet pumps to the wide range of conditions encountered in oil wells. Nozzle and throat sizes available from National Production Systems, Kobe, Inc., and Guiberson Hydraulic Pumping Systems, the three major suppliers of oilfield jet pumps, will be presented. Appendices will include hand-held calculator application programs for a TI-59 and an HP-41C. Comparisons between the predictions from the calculator programs and the sophisticated programs used by the pump manufacturers as well as actual well data, will demonstrate the applicability and limitations of the techniques presented in this paper. The discussion will include Potential sources of error and the sensitivity of the calculations to uncertainties in the well data.

Incomplete pump fillage is often associated erroneously with a "pumped-off well", meaning that the pump displacement exceeds the production capacity of the reservoir, ignoring the fact that there are two other causes of partial liquid fillage: gas interference and the presence of a flow restriction or excessive pressure drop at the pump intake. The result of a misdiagnosis is to incorrectly set the mode of operation of pump-off controllers, variable speed drives or timers thereby loosing significant amounts of production. This paper describes the three causes of incomplete pump fillage, presents several sets of field data for the various cases, discusses how to combine dynamometer and fluid level records to correctly identify the source of the problem and presents recommendations for possible solutions.

The economic benefits to be obtained from use of a through-tubing bridge plug have long been known by the petroleum industry. However, early attempts to produce a reliable through-tubing bridge plug for casing were not successful. Sustained engineering effort was begun by Schlumberger in the middle 60's to devise a through-tubing bridge plug that would give consistent plugging results. Many problems that had not been previously recognized were highlighted. This engineering effort produced the "Plus Plug", a new concept in through-tubing bridge plugs, which was introduced to the field in the late 60"s. Actual usage in the field has brought additional problems into focus. Additional engineering effort is being expended to improve the plus plug so that it will be capable of a wider range of usage.

Because of the complexities of pumping dense phase C02, it is recommended that one supplier provide all components. These should be completely skid mounted with pump, driver and accessories,- valves, headers and controls all preassembled, wired and tested.

Sand problems can cost a company valuable time, money, and resources. Various methods have been used to reduce sand problems experienced in rod pump operations. This presentation will propose an alternative solution utilizing pump screens and tubing screens to handle the sand problem and increase production and profit capability. Illustrations will be examined, which explain how pump and tubing screens function, and case studies will be reviewed that discuss the benefits and limitations of the screens.

Sand problems can cost a company valuable time, money, and resources. Various methods have been used to reduce sand problems experienced in rod pump operations. This paper will present an alternative solution utilizing Pump Screens and Tubing Screens to handle the sand problem and increase production and profit capability. Illustrations will be examined which explain how the Pump and Tubing Screens function, and case studies will be reviewed that discuss the benefits and limitations of the screens.

Sand problems can cost a company valuable time, money, and resources. Various methods have been used to reduce
sand problems experienced in rod pump operations. This presentation will propose an alternative solution utilizing pump
screens and tubing screens to handle the sand problem and increase production and profit capability. Illustrations will be
examined, which explain how pump and tubing screens function, and case studies will be reviewed that discuss the
benefits and limitations of the screens.