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.

Hydrochloric acid has been used for more than 40 years to improve production in oil and gas wells. Many techniques have been used to improve results of hydrochloric-acid treatments. One of the most important advances has been recognition that fracturing occurred during the majority of acidizing treatments. This enables the use of fracturing principles to increase live acid penetration. Unfortunately, actual results did not correlate with predicted results. This prompted the use of many techniques to improve results. Some of these are listed below. 1. Acid retardation 2. Increased acid concentration 3. Increased injection rates 4. Increased fracture width to decrease area-to- volume ratio 5. Improved matrix leakoff control 6. Increased pad volumes 7. Improved computer programs. All of these approaches had the purpose of increasing live acid penetration, and thus improving conductivity to the wellbore. Although each action helped either separately or when used in various combination, still a large gap remained between predicted and actual results. The problem has been that the work was based on the assumption that leak off was due to matrix permeability.

The necessity of developing cleaner fluids for the purpose of well stimulation has been the topic of current discussion among oil company and service company personnel alike. In fracturing, the incorporation of specific quantities and types of gelling agents and fluid-loss additives has been considered only as means by which to obtain effective viscosities for proppant transport, fracture width development, and efficiency via low leak-off of fluid away from the direction of fracture penetration. Since it has been established by several investigators19 2 that fluid-loss additives and natural agent gelling compounds may contribute significantly to formation damage, a need for a clean fluid encompassing the properties of effective viscosity, low fluid-loss, efficiency and comparable economics is evident. This will be shown in tabular and application history forms. One solution to the problem is to utilize a highly efficient ultra-low residue, chemically substituted, natural polymer at low concentrations, and employ the principle of cross-linking to allow actual link-up of the molecules to provide several folds of viscosity increase over that obtainable by the low concentration base gel; and via the process of interlocking or connecting molecules of guar polymer, create an excellent fluid-loss control mechanism such that little or no additional fluid-loss additive is required?, 4 This system may be batch-mixed into frac tanks unlike the predecessor high concentration cross-linked gels. The guar used is of a relatively new type, being a highly refined (0.5% residue) chemically substituted hydroxyalkyl-type. This product's molecular structure is compared to the conventionally used guar molecule in Fig. 1. When cross-linked at a concentration of 15 lb/1000 gal. aqueous phased fluid, the individual hydroxyalkyl molecule, as shown in Fig. 2, is cross-linked by bonding, as shown in Fig. 33. It may be stated that the use of the abovementioned hydroxyalkyl polymer in the cross-linked state at relatively low concentrations compared to conventional oil or water-based fracturing systems is a comparably efficient or more efficient, more effective fracturing system. The evidence for showing the low-residue hydroxyalkyl cross-linked guar system to be comparable, or better, than conventionally designed gels containing between 20 lb and 60 lb gelling agent in addition to 20-40 lb of fluid-loss control material is borne out by viscosity, fluid loss, friction loss, fluid efficiency, and cost evaluation testing. See Table 1.

Acrolein (2-propenal) is a potent biocide and sulfide scavenger which has been used to mitigate bacterial and iron sulfide problems in secondary oilfield recovery systems. The effectiveness of acrolein is due to its _,_-conjugated double bond which reacts with sulfhydryl and amine groups on bacterial proteins as well as irreversibly reacting with sulfide ions in hydrogen sulfide (H2S) and iron sulfide. This paper discusses the applications of acrolein in water injection systems to control bacteria, H2S, and iron sulfide scale problems impacting water clarity, injection flowline integrity, and injection well performance. Data are presented on three case studies which describe 1) the reduction in injection well failures due to acid producing bacteria, 2) remediation of iron sulfide formation face damage in injection wells via squeeze applications, and 3) remediation of iron sulfide fouled injection wells via a novel topside batch treatment program.

In recent times, a tremendous amount of effort has gone into the development on nonaqueous fracturing fluids. These fluids, usually alcohol or high-gravity hydrocarbons, which may contain propane, carbon dioxide or nitrogen, have been utilized in the stimulation of many formations. The above systems, while normally being successful, have some shortcomings. Generally the fluids are expensive and many require specialized equipment. With the introduction of a new fracturing fluid based on mixtures of alcohol and water, a lower cost alternative is now available. The alcohol-water systems are particually applicable in low-porosity, low-permeability gas reservoirs. Laboratory tests with formation cores show that the effective permeability to gas following injection of alcohol solutions is much more rapid than when water is the injected fluid. These fluids, which can contain from 20 to 40% methanol, also aid in protecting water-sensitive formations against clay swelling and migration. In addition, the presence of alcohol markedly reduced the surface tension of the fluid. These advantages permit rapid production fo the fracturing fluid from the formation. Many field tests have shown that rapid cleanup is obtained with this system. This paper presents a description of the fluid system, various viscosities that may be obtained, including crosslinked or delayed gels, as well as laboratory field results.

As the energy situation becomes more critical and more domestic oil is desired, new methods of stimulation are needed. Conventional methods generally have not been successful in treating thick or massive pay sections whether in cased or open hole. This has been true for squeeze cementing as well as fracturing and acidizing treatments. In the Levelland-Sundown areas of West Texas, most of the producing formations are thick, fractured limestones of varying porosity and permeability. The problem here has been to treat the low-permeability or tight zones as well as the more permeable zones. Many diversion methods have been tried without success. These have included straddle packers, ball sealers, and the suspended-solids type of blocking agents. While all of these may force the stimulation fluid to enter the tight zone, the fluid generally will penetrate only a short distance before seeking a fracture back into the more permeable zones. As a result, fluids from later stimulation treatments have undoubtedly been injected back into the originally treated zone time after time. The same is probably true of cement when attempting to squeeze-off undesired zones such as water-producing zones or channeled zones in injection wells. A new method of diversion has been employed with a high degree of success in this area during the last two years. The method involves the use of two fluids, one "tagged" with a radioactive material and another "untagged" fluid. The "tagged" fluid normally is pumped down the annulus while the untagged fluid is pumped simultaneously down the tubing. A detection tool, run on a wire line, is used to monitor the interface between the two fluids. The interface indicates the place of entry of the two fluids into a zone. The location of the interface is controlled by means of pump rate. It can be moved up or down by varying the pump rate down the tubing or annulus or both. The interface method allows control of stimulation fluids not only at the wellbore but out in the formation as well. Figure 1 illustrates one type of interface treatment. In this example, the problem is to acidize a low-permeability zone below a zone of higher permeability. In this case radioactive water _ is pumped down the annulus while acid is pumped simultaneously down the tubing. The radioactivity detector is located in the tubing and the interface is controlled at the top of the low-permeability zone. Most acid inhibitors are capable of protecting the wire line and detection tool from damage by the acid. However, in extremely deep or hot wells, special inhibition requirements may be required by the wireline company. In Fig. 2, the problem is exactly the opposite of that in Fig. 1 and is the problem usually encountered in the Levelland-Sundown area. Here the zone has

Since the early days of oil production, operators have been plagued by emulsified oil. It has been estimated that about 70 per cent of all crude oil is produced in the emulsified form. Before this oil can be transported and refined the emulsified water must be removed. In the early days of the industry, pipe lines would accept oil containing upwards of 5 percent water, while today they will accept only 1 per cent water of basic sediment. Many methods of removing the water and emulsion from this production have been tried with varying degrees of success. In the early days of flush production the "cut oil" or "rolly oil" was flowed or pumped into large earthen pits where it was subjected to treatment by the sun. This slow process produced a top layer of dry or "clean" oil which was decanted periodically and sold. Most of the light fractions were lost in the process but little thought was given to the loss as kerosene was the more important fraction and oil was being produced as fast as it could be dehydrated and sold. Later, some improvements were made by the use of hay tank filters. Centrifuges were tried at some refineries and electrical demulsification was used in the oil fields as well as in refineries. When the operators discovered that lye, washing soda, and strong soap powders such as the old "Gold Dust" rosin soap would break these emulsions, the use of chemicals in oil fields began.