Over the last 50 years hydraulic lift has proven its worth to operators worldwide in varying lift conditions, both on and offshore. Since the development of hydraulic lift in the 1930's, the products and technology have rendered hydraulics a viable means of artificial lift in today's oilfield. Through understanding and foresight, the operators can optimize the production and minimize the operating expense through equipment flexibility and performance. By utilizing the flexibility of a hydraulic lift system, both the surface and subsurface equipment can adjust to changing well conditions through the life of the well without major equipment change-outs. Optimizing equipment performance through efficiency, treatment, and monitoring, the operator is able to keep a handle on lifting costs. The following will cover the flexibility and performance on a casing-free single well hydraulic lift system. Many of the topics covered also apply to other types of single zone completion installations such as parallel-free, gas vent, etc.

Continually rising costs for producing petroleum make it mandatory for the oil industry to search for more efficient, improved materials and simplified, longer-life equipment. "Flexirod", the newly marketed flexible pumping stand, possesses characteristics that drastically reduce corrosion fatigue and thereby frequency of well pulling, lower horsepower requirements, make handling easier and faster and create the potential for new concepts in pumping equipment. This paper describes in detail the construction and operation of a nylon-covered multi-wire strand that functions as a continuous sucker rod. It is sufficiently flexible and light in weight to be placed on a reel for easy, rapid, economical handling. Development has been underway for over six years and numerous lengths are in actual operation in wells varying from 1500 ft to 5000 ft in depth.

During 1969, Getty Oil Company, which has since become part of Texaco, Inc., initiated a massive field automation program in it's Kern River Oilfield in California. The result was the SCAN system, or Sampling, Control and Alarm Network, which can be credited with supplying most of the field data and operating information necessary for the successful transformation of that 70 year old oilfield from a daily oil production of 45,000 barrels to a maximum of over 100,000 barrels per day. The system is still in full operation and has since been expanded to service 4600 wells instead of the 2200 wells connected at its inception. SCAN as an operating system has been well reported in prior literature (See ref.) so only a brief functional description is given here. This paper limits its scope to a portion of the system rarely touched upon by system analysts, the field-end hardware components which supply well data to the SCAN computer center. Especial attention is given to the individual well flow sensors, often referred to as flow/no-flow switches. These devices are worthy of special examination because they supply a stream of data which is of surprising importance to both engineering and operating groups. Their selection and application problems are also pretty typical of those encountered with other items of data producing hardware.

Increased drilling and operating costs have resulted in a greater number of dually completed wells. Most operators prefer two parallel tubing strings over concentric installations, since the development of detachable two-string packers and split wellhead equipment for parallel strings. This paper discusses in detail the flow valve selection for gas lifting both zones of dual with a common injection gas source. The material is presented in a manner which permits an operator to choose the proper valve design for a dual without a previous thorough knowledge of gas lift principles. The design considerations using fluid operated, intermittent and continuous flow gas lift valves for dual installations are discussed. An efficient installation is based on the combination of producing characteristics of the two zones. Proposed valve installations are outlined for the following combinations: 1. Both zones continuous flow. 2. One zone continuous flow and the other zone intermittent flow. 3. Both zones intermittent flow. 4. Producing characteristics of either or both zones unknown.

The world's largest flue gas operation is being conducted in the Block 31 Field, Crane County, Texas. This multi-pay field was discovered by The Atlantic Refining Co., now Atlantic Richfield Co, in Nov. 1945. Early in the field's life, the industry's first miscible displacement program was started in the Devonian reservoir. The 54 MMCF/D flue gas plant started operations on March 8,1966. The miscible program had been conducted for approximately 17 yrs. Prior to construction of the flue gas plant, a conventional gasoline plant and injection facilities were in operation. By burning a portion of the absorber residue gas in a controlled atmosphere, the volume can be increased 9-11 times. Operation of this flue gas plant resulted in not having to purchase 30-40 MMCF/D of natural gas, permitting the sale of 20-30 MMCF/D of produced gas and assuring a good supply of displacement gas for the reservoir. The flue gas plant will extend the economic life of the injection program.

Primary cementing is simple, i.e., displace drilling mud with cement to form a hydraulic seal between the pipe and the borehole. All too often, efficient drilling mud removal is not achieved, the cement cannot form a hydraulic seal and the result is communication between zones. This paper provides a discussion on the use of a fluid caliper to improve the success rate of primary cementing. The fluid caliper is an extension of mud conditioning and, used in conjunction with centralizers and other proper cementing procedures, provides for a surer primary cement job. Procedures and case histories are included.

Sucker rod pumps are installed in approximately 90% of all oil wells in the U.S. Although they have been widely used for decades, there are many issues regarding the fluid dynamics of the pump that have not been fully investigated. A project was conducted at Sandia National Laboratories to develop an improved understanding of the fluid dynamics inside a sucker rod pump. A mathematical flow model was developed to predict pressures in any pump component or an entire pump under single-phase fluid and pumping conditions. Laboratory flow tests were conducted on instrumented individual pump components and on a complete pump to verify and refine the model. The mathematical model was then converted to a Visual Basic program to allow easy input of fluid, geometry and pump parameters and to generate output plots. Examples of issues affecting pump performance investigated with the model include the effects of viscosity, surface roughness, valve design details, plunger and valve pressure differentials, and pumping rate.

During the last ten years, the acoustical well sounder has really come into its own as a production tool. These instruments are used to determine the fluid level in wells by the echo method. In addition, the location of various subsurface equipment items can be determined. At the present time, there are two major manufacturers of acoustical well sounders. Both of these manufacturers use two small trunks to house their instruments. One trunk contains the wellhead attachment with the necessary interconnecting cables. The second trunk contains the amplifier-recorder.

Ideally when controlling a rod pumped well, is it important to have often and accurate fluid levels. However in the absence of the availability of these measurements, fluid levels must be calculated using fluid properties and pressure gradients. An important part of those calculations is being able to correctly approximate the fluid load. The fluid load is the difference between the upstroke fluid load and the downstoke fluid load. in this paper the accuracy and validity of a methodology for computing fluid load lines and therefore fluid level is verified through the application of the fluid load line calculation to a set of field data, for which a fluid level is available for each stroke analyzed.

The water-logging of low pressure gas wells is a serious problem in some areas, and tends to become more grievous as field pressures drop. The free travel plunger, an old idea in the petroleum industry may prove in some instances to be more economical than any other known method of meeting this problem. The paper explains the theory of the free travel plunger, presents a few case histories, and generally compares the economical and operational aspects of this method with the more popular siphon string and pumping methods.

Surfactants have performed well in a variety of applications with regard to stimulation. The role of surfactants, or surface active agents, in both acidizing and fracturing has been somewhat taken for granted; but these agents nonetheless play an extremely important and ever-increasing part in almost all successful stimulation treatments. Surfactants have been discussed thoroughly in the literature with respect to use in oil well treating fluids. Until recently, most surfactants used in stimulation have come from one of two families. The most commonly used are hydrocarbon-based, and the others consist of silicone-based materials. Numerous blends of these types are used to deal with a number of situations. In varying concentrations, the above-mentioned "conventional" surfactants have been used in a variety of applications which are as follows. 1. To lower the surface tension or interfacial tension of a fluid. 2. To provide non-emulsion characteristics to a fluid. 3. To provide emulsion-breaking characteristics to a fluid. 4. To provide emulsion-forming characteristics to a fluid. 5. To provide foaming characteristics to a fluid. 6. To suspend fines or particles in fluids. 7. To retard or extend the reaction time of various acids. 8. To allow more effective penetration by aqueous or acid systems. 9. To facilitate a desired wetting function on a particular surface (i.e., metal, rock, etc.). 10. To assist or prevent various types of material in adsorbing to particular surfaces under certain conditions or to allow low adsorption. 11. To provide protection from various harmful reactions (i.e., corrosion, precipitation, etc.).4 12. To allow interaction with other physical problems in the oil or gas reservoir such as fluid imbibitions, capillarity, saturation or permeability.5"6 13. To allow water block removal or more effective treatment load recovery. 14. To improve wetting and thereby hydration of polymers used in stimulation. There are probably other uses which could be mentioned, but those above are generally considered most essential. Correct use requires careful selection of a particular surfactant type. The criteria for surfactant selection for use in a treatment is given below to emphasize the importance of appropriate materials.

Foam cement's ultra-light density and high compressive strength characteristics have been employed in the Permian Basin to protect low-fracture gradient formations. In addition to standard casing jobs, squeeze cementing results have been greatly improved through use of fast setting, expansive foam cements to obtain an effective squeeze without breaking down weak formations. With this unique fluid, squeeze cementing jobs have had a significantly higher success ratio for controlling water zones and sealing corroded casing. In cases where standard lightweight cement slurry compositions have proven ineffective because pumping pressures exceed formation breakdown pressure, foam cement has been used to help prevent fracturing weak formations. Field results and job procedures will be emphasized to illustrate how foam cement is being used in the Permian Basin to improve squeeze cementing job results when low formation breakdown pressures are present.

For the past several years, foam has been used in many treatments as a fracturing fluid. Although many different types of reservoirs have been stimulated with foam, the primary zones of interest in Eastern Kentucky and Southern West Virginia have been the Berea Sandstone and the Devonian Shales. Due to the nature of these formations, i.e. low permeability, low bottom-hole pressure and water sensitivity, foam fracturing has been a successful technique. This paper presents the basic background theory of foam and presents several basic treatment designs which have been used successfully in the Devonian Shales and Berea Sandstone. Production histories for up to two years on a number of wells fractured with foam are compared to production histories of offset wells which were conventionally fractured with gelled water. In all the side-by-side comparisons, foam fracturing was found to give production results either as good as, or better than, conventional fracturing with gelled water.

Foam has been used successfully as a fracturing fluid as previously described by Blauer and Kohlhaas." They presented analytical measurements of fluid-loss coefficients and sand settling rates. Other investigator.9lo have discussed use of foam in other oilfield applications. Blauer, Mitchell and Kohlhaas" have reported rheological properties of foam. The physical structure of aqueous foams used for fracturing is used to explain foam viscosity and sand-supporting properties. Figures are presented comparing fluid-loss coefficients, sand-settling ratios, and fracture areas for foam and other common fracturing fluids used in West Texas. Chemical compatibility of foaming surfactants with formation fluids and fracturing-fluid additives is discussed. Core flow data and case histories show foam can be used to stimulate formations in the West Texas area.

Dynamic laboratory testing of foamed acid on limestone cores has established the effectiveness of foamed acid as a stimulation fluid. The effects of foam quality, foam stability, and chemical. compatibility on fluid loss and fracture flow capacity were investigated. Recommendations are presented for deriving maximum benefits from a foamed acid treatment. Field results are presented that show the effectiveness of foamed acid in the stimulation of both oil and gas wells.

Foamed stimulation has been broadened to include the use of high- and low-quality (30% to 75% nitrogen) foams for acidizing soluble formations. To insure correct placement of foamed acidizing systems, foamed diverting techniques using high-quality (80% to 90% nitrogen) foamed water systems are currentIy being employed in several West Texas and Southeast New Mexico areas. Application of these techniques has been successful in both producing and injection wells. The mechanics of these systems will be discussed along with comparative results and current cost economics.

Foamed cement is a relatively new concept to oil/gas well completions. Foamed cement slurries produce good results provided several factors are considered. This paper will present several job design factors which help provide good results. It will also discuss several practices which should be avoided.

An infill drilling project was undertaken in the Eunice Monument South Unit (EMSU) to help balance the current water flood and strategically place producers and injectors into a smaller spacing and configuration. Past developments and treatments to better flood the units were initiated in 1996 to characterize the reservoir and improve the flood conformance. Knowledge gained led to the implementation of the infill drilling EMSU project and identified the criterias needed to offset the problems that would be faced. Crossflows and high water influxes would be encountered, and determination of a system to gain the best possible zonal isolation during the primary cementing operations was established in the planning process. Follow-up ultrasonic cement evaluation logs were run to determine the performance and integrity that was achieved. Controlled injection profiles in the newly developed injection wells and the ability to control the placement of fracture stimulation in new producers were reflected in the well's performance.

Foamed hydrocarbons have been applied with great success in paraffin and heavy hydrocarbon penetration, foamed fracturing treatments, and fluid cleanout in wells in which hydrostatic pressure interferes with or completely stops gas production. Results of lab and field tests show this system to be effective as well as economical as an alternative in well treatment. He paraffin and heavy hydrocarbons removed in foamed aromatic hydrocarbons constituted up to 41 percent of the total volume of solids removed after a 1 hour shut-in period. A nonproductive well in the San Miguel formation which had been shut-in for a year was fractured with foamed gel condensate resulting in 70 MCF gas/day. A fracturing system designed with foamed gelled kerosene used to fracture the Crockett San Formation produced a 105 BOPD and 130 MCF/day well where previous gelled kerosene fracturing treatments yielded 12 to 30 BOPD and no gas. After 30 days, the well still made 70 BOPD and 100 MCF/day. Gas wells in the Sonora area have periodical condensate buildups which restrict the gas flow. With the addition of a hydrocarbon foamer, the hydrostatic head was removed in the form of foamed condensate, allowing production of the natural gas. Procedures and results of lab and field tests will be discussed along with comparative results of more conventional treatments.

Market competition, shareholder returns, declining product price, technology, safety and environmental legislation continually challenge the oil and gas industry. An additional challenge faced by many oil and gas producers is effectively maintaining equipment to acceptable levels in order to sustain production targets. Asset reliability has become a focal point of discussion both domestically and internationally. Asset reliability can become a significant liability to the owner if the equipment is not in a state of production readiness or if an unforeseen catastrophic safety or environmental event occurs. Many industry leaders are successfully meeting the challenge by adopting reliability based asset management. Today, industry organizations have successfully aligned their business plan with reliability management. The results are very impressive. This paper will examine common threads, which tie reliability asset management with corporate business goals.

This paper describes an analytical procedure for forecasting the life expectancy of rock-bit journal bearings. Actual performance data and reliability analyses are used to establish empirical relationships and graphs that relate risk of bearing failure to operating parameters and drilling cost. The paper was originally published in SE Drilling Engineering, June 1990 (Volume 5, No. 2).

This paper describes an analytical procedure for forecasting the life expectancy of rock-bit journal bearings. Actual performance data and reliability analyses are used to establish empirical relationships and graphs that relate risk of bearing failure to operating parameters and drilling cost. The paper was originally published in SE Drilling Engineering, June 1990 (Volume 5, No. 2).

Paraffin and/or Asphaltenes, present in all oils/condensates, are responsible for damaging a majority of wells in the United States. Increasing production from these wells can be accomplished by removing the organic damage but the increase may be of short duration unless new damage is prevented. Squeeze treatments using paraffin and asphaltene inhibition chemicals have successfully held oil and gas production increases at elevated levels following stimulation by keeping new damage from reoccurring for greater than six months. The extended high levels of production are needed to pay for cost of the sometimes, large treatments required to clean and squeeze the wells. This paper will describe the types of damage possible in flowing wells, pumping wells, CO2 floods, water floods, and gas floods. Cleanup and Squeeze treatments will be described and case histories presented of successful treatments.

Sedimentary formations are the usual target for oil and gas exploration. Of the many classifications of these zones, carbonate and elastic deposits most often bear hydrocarbons in commercial quantities. Clastic formations are composed of broken and fragmented pieces of older existing rocks. Sands or sandstones can be classified as elastics. They result from erosion and weathering of land masses. The eroded particles are transported by various means to an area of deposition where they are laid down in somewhat orderly strata. Carbonate rocks result from the precipitation of minerals held within an aquatic environment. Carbonates are formed of varying concentrations of calcium and magnesium carbonates. Most texts represent sedimentary rocks as orderly strata arranged in uniform distribution. It is very important to remember these zones are actually composed of numerous individual grains of fundamental makeup materials. The size, shape and homogeneity of the matrix greatly contribute to a formation's ability to store and later transmit hydrocarbons. For the purpose of this discussion, any change in the potential for production caused by foreign fluid exposure will be classified as formation damage. There are four primary formation damaging mechanisms commonly recognized in most sedimentary hydrocarbon bearing zones. These mechanisms are (1) the hydration and swelling of formation clays, (2) the invasion and/or migration of solids into and within the formation, (3) the formation of water blocks, and (4) the formation of emulsion blocks. The damage resulting from any one of these sources can be seriously detrimental to well productivity as well as extremely long lasting. The prevention of these types of damage is much less involved than rectification after damage has occurred.

Information essential to interpretation of hydrocarbon and/or water productivity is not available from a single measurement technique, whether it be core analysis, complete suites of electrical logs or bottomhole pressure build-up or fall-off tests." The best features of each technique can be combined to obtain mutually consistent interpretations which result in improved evaluation of potentially productive intervals in a well. Methods are described which combine core analysis data with electrical resistivity logs. This combination yields information required to select zones for completion, zonal producing characteristics and their possible down-dip productive limits. To accomplish this, core analysis and appropriate reservoir fluid data are converted to values of resistivity. These values are plotted on transparent overlays which are compatible with resistivity scales reported on the downhole resistivity log.