This paper describes the development of a downhole cleaning device based on fluidic oscillation. This fluidic oscillator is used for removal of deposits from the near-wellbore area, perforations, and screens. The cleaning device creates pressure waves within the wellbore and formation fluids that (1) break up near-wellbore damage and (2) restore and enhance the permeability of the perforations and near-wellbore area. Fluidic oscillators have been used for various purposes in a wide range of industries for many years. They typically exhibit reliable oscillation over a wide range of flow rates and have no moving parts. The cleaning tools presented here are specifically designed for high-pressure, submerged operation and maximum pressure-pulse amplitude. The unique design has been carefully refined through theoretical and experimental methods. This paper discusses fluidic oscillator theory and presents a numerical analysis of a specific oscillator design, as well as an analysis of experimental test data at various flow rates. The provided case histories demonstrate the utility of fluidic oscillation as a wellbore-cleaning device. Introduction The industry has taken a quantum leap with the release and commercial application of the next generation of fluidic oscillator near-wellbore stimulation service. Over 50 successful field jobs have been performed with this new technology. In many cases, production increased over previous treatments that used an older type of fluidic oscillator. Several unique case histories resulting in production increase and job time reduction are discussed later in this paper. The new design is unique in its adaptation of the classical feedback loop oscillator design. One innovative design feature is the ability to tune the output frequency of this tool by scaling the oscillator pattern for optimum cleaning and stimulation efficiency as our knowledge and database of production results grows. Unlike other "use-as-is" fluidic oscillators this next generation fluidic oscillator design is "living" technology that can grow and adapt to field feedback. The fluidic oscillator is a downhole, cleaning device based on patented and patent-pending fluidic oscillator technology that generates alternating bursts of fluid. This tool is used for the removal of deposits from the near-wellbore area, perforations, and screens. The cleaning device creates pressure waves within the wellbore and formation fluids that can (1) break up near-wellbore damage and (2) restore and enhance the permeability of the perforations and near-wellbore area. This tool incorporates the proven, classical feedback loop theory for generation of the Coanda effect. Fluidic oscillators are available in sizes from 1.69 to 2.88-in. OD and are adaptable to both jointed pipe and coiled tubing applications. The tools operate at an optimal pressure drop of approximately 2,000 psi and oscillate at a frequency between 300 to 600 Hz. The tools are rated to 400°F and are suitable for sour gas service. Fluidic oscillators incorporate several design features that help improve reliability, function, and performance while reducing tool life-cycle costs. These features include:A patented, metal-to-metal, tapered seal---no moving parts or seals.Side jets that maximize cleaning energy by direct impingement on the casing or near wellbore.Multi-angular fluid impingement.Higher energy output over a narrower frequency range than conventional oscillators.Turbulence created by side and down jets that helps lift debris out of the hole.A down jet that clears debris, obstructions, or bridges while tripping into hole.Adaptability for running on either coiled tubing or jointed pipe.Customized inserts to maximize flow rate and pressures.Replaceable inserts manufactured using modern high-tech electrical discharge machining (EDM) process.

Tubular restrictions from scale buildup can significantly reduce hydrocarbon production and the overall production capacity of a well. Before production can be restored, this buildup must be removed. Although scale buildup is a global problem, the material composition and characteristics of scales can vary drastically, even within the same field. Therefore, most tools traditionally used for scale removal cannot efficiently remove scale in all well conditions. This paper discusses a recently developed, customized jet cleaning tool that resolves some of the problems inherent with scale-cleaning operations. Traditional jet cleaning tools have not adequately controlled jet dwell time, which has severely impacted their operational performance. Depending on the type and hardness of the scale, many removal methods cannot control the jet dwell time required to accomplish scale removal. Because the required jet dwell time increases with the hardness of the buildup material, cleaning efficiency can be measured by the capability of the scale-removal method to control dwell time. A new, slow-rotating jet cleaning tool maximizes jet dwell time without introducing repetitive cyclic effects on a coiled tubing (CT) workstring. The slow-rotating jet cleaning tool can also be used for cutting tubulars. Previously, tubulars could only be cut by mechanical, explosive, or chemical methods. CT was used either for deploying positive-displacement motors (PDM's) for rotating mechanical cutters or to deploy pressure-activated firing devices that initiated the firing sequence in explosive or chemical cutters. The slow-rotating jet cleaning tool can be used to cut tubulars when limitations exist for other cutters. This paper discusses the evolution of CT cleaning procedures, alternatives to cleaning with CT, and the design and application of the new slow-rotating jet cleaning tool. Case histories discuss the use of the jet cleaning tool for removing scale and production buildup on tubing walls. The new tool can be used for performing through-tubing cuts and can help reduce service costs for difficult applications, such as those involving long bottomhole assemblies (BHA's). The capacity of the new jet cleaning tool to control jet dwell time and pump abrasive fluids helps reduce the risks, obstacles, and costs associated with traditional cleaning and cutting methods. Introduction Scale deposits on tubing walls and perforations can stop well production, inhibit the injection of well fluids, and cause downhole production equipment to become lodged. If left untreated, these problems will compound, and hydrocarbon production will continue to decrease. Early Use of CT for Cleaning. The choice of a scale-removal treatment is often affected by cost. Treatment methods such as acidizing or milling with small-diameter tubing can be expensive. Because CT operations could be performed under live-well conditions, CT was introduced in the 1970's to provide a lower-cost option for scale removal. CT provided a washing action for removing scale materials. When acids were run through the tubing, they reacted chemically with the scale, extracted waste materials from the tubing, and restored the fluid flow path to the base pipe. However, using CT alone to remove scale was insufficient. Several factors affected the cleaning efficiency of CT:The fluid-pumping equipment delivered more hydraulic horsepower (hhp) to the CT than the CT could withstand.Because of the friction pressure of the small string diameters and pressure ratings of the tubing, appoximately 80% of the available hhp was lost.The tools that were placed on the end of the CT to assist with cleaning caused an additional 15% loss of available power. Consequently, only a small percentage of the hhp from surface pumping equipment was available for removing buildup. Early Use of CT for Cleaning. The choice of a scale-removal treatment is often affected by cost. Treatment methods such as acidizing or milling with small-diameter tubing can be expensive. Because CT operations could be performed under live-well conditions, CT was introduced in the 1970's to provide a lower-cost option for scale removal. CT provided a washing action for removing scale materials. When acids were run through the tubing, they reacted chemically with the scale, extracted waste materials from the tubing, and restored the fluid flow path to the base pipe. However, using CT alone to remove scale was insufficient. Several factors affected the cleaning efficiency of CT:The fluid-pumping equipment delivered more hydraulic horsepower (hhp) to the CT than the CT could withstand.Because of the friction pressure of the small string diameters and pressure ratings of the tubing, appoximately 80% of the available hhp was lost.The tools that were placed on the end of the CT to assist with cleaning caused an additional 15% loss of available power. Consequently, only a small percentage of the hhp from surface pumping equipment was available for removing buildup.

The design of high-torque, high-reduction gear reducers often requires the use of multi-stage gearing, planetary gear systems, or both. Because these systems contain many independent parts, they often become bulky. When these systems will be used in downhole oilfield equipment, compactness can become a crucial factor. Moreover, downhole oilfield equipment generally requires that areas of the system be reserved to provide some fluid flow-path around the equipment. A unique gear reducer was designed to accommodate this need for compactness. The new reducer system consists of only four gears, two of which are built as a single part. All four gears are positioned roughly concentrically within a donut-like space, and the open center accommodates fluid flow. Unlike other gear reducer systems, this system employs not only a ratio (divisional) method, but also a unique subtraction method. Consequently, a reduction of more than 2000:1 is possible. With this radical design, conventional gear teeth cannot be used if good meshing is desired. Subsequently, a special gear tooth shape was designed to provide surface contact between the teeth. With this special shape, full contact of more than 30% of the teeth can be achieved, compared to one or two teeth in standard designs. Thus, the new system also improves load-transmitting capacity. In this paper, the design of the new gear reducer is discussed in detail. A specific application in which high-pressure, sand-laden slurry is pumped through the center of this gear reducer is also discussed.

This paper discusses the evolution of CT cleaning procedures, alternatives to cleaning with CT, and the design and application of the new slow-rotating jet cleaning tool. Case histories discuss the use of the jet cleaning tool for removing scale and production buildup on tubing walls. The new tool can be used for performing through-tubing cuts, and can help reduce service costs for difficult applications, such as those involving long bottomhole assemblies. The capacity of the new jet cleaning tool to control jet dwell time and pump abrasive fluids helps reduce the risks, obstacles, and costs associated with traditional cutting and cleaning methods. IntroductionScale deposits on tubing walls and perforations can stop well production, inhibit the injection of well fluids, and cause downhole production equipment to become lodged. If left untreated, these problems are compounded, and hydrocarbon production will continue to decrease.Early Use of CT for Cleaning. The choice of a scale-removal treatment is often affected by cost because treatment methods such as acidizing or milling with small-diameter tubing can be expensive. The introduction of CT in the 1970s provided a lower-cost option for scale removal because CT operations could be performed under live well conditions, reducing down time.CT provided a washing action for removing scale buildup materials. Acids run through the tubing chemically reacted with the scale, extracting waste materials from the tubing and restoring the flow path of the fluid to the base pipe. However, actually removing the scale buildup with CT was insufficient. Several factors affected the cleaning efficiency of CT:The fluid-pumping equipment delivered more hydraulic horsepower to the CT than it could withstand.Approximately 80% of the available horsepower was lost to the small string diameters and pressure ratings of the tubing.The tools that were placed on the end of the CT to assist with cleaning caused an additional 15% loss of available power. Consequently, only a small percentage of the hydraulic horsepower from surface pumping equipment was available for removing buildup. AbstractTubular restrictions from scale buildup can significantly reduce hydrocarbon production, subsequently reducing the production capacity of a well. Before production can be restored, this buildup must be removed. Although scale buildup is a global problem, the material composition and characteristics of scales can vary drastically, even within the same field. As a result, most tools traditionally used for scale removal cannot efficiently remove scale in all well conditions. This paper discusses a recently developed, customized jet cleaning tool that addresses the problems inherent with scale-cleaning operations.Scale removal can be difficult because many removal methods cannot control jet dwell time, which is the time required to accomplish scale removal based on the type and hardness of the scale. Because jet dwell time increases with the hardness of the buildup material, cleaning efficiency is measured by ...

Zonal isolation in injection, geothermal, and producing wells is critical both to reservoir evaluation efforts and to operations, but often, cementing between the casing and the wellbore is still the only method of zonal isolation performed in many wells. Although zonal isolation and well diagnostics techniques have improved, primary cementing techniques may be inadequate for some reservoir conditions, resulting in undesirable water flows, gas flows, or both. If zonal isolation is inadequate, then expensive, often complicated remedial cementing work will be needed for improved well and reservoir performance. If conformance technology is applied during the drilling phase, it can improve the performance of primary cementing processes, making them safe and economical. Conformance treatments seal problem intervals before primary cementing, thereby alleviating potential well-control problems. These treat-ments also help ensure successful primary cementing operations and prevent isolation loss caused by the casing expanding and contracting during production-pressure cycles. The formation itself, rather that the cement sheath alone, becomes the zonal isolation mechanism. During the drilling phase, zonal isolation requires the use of coiled tubing, a hydrajetting device, a depth-correlation device, and a sealant. The sealant should be water-thin during placement, and should become an elastic polymer only after it is set in place. This zonal isolation technique requires an understanding ofdepth correlation to open hole logs, through the use of mud-pulse technology, andhydrajetting techniques that remove mud filter cake while placing the sealant. This paper presents examples of this technique for a 7 7 /8-in. wellbore and a 13 1/2-in. wellbore. Introduction The creation of an effective reservoir management strategy requires an operator to achieve zonal isolation, model past-production performance, and predict applied technology's influence on future production performance. Satter and Thakur1 state that the current challenges to effective reservoir management areimproved definition of reservoir characteristics,improved tracking of fluid movements through the reservoir, andimproved control of fluid movements in the reservoir. Reservoir diagnostics and performance predictions require the complete isolation of the intervals under evaluation, and conventional zonal isolation methods have proven inadequate for many reservoir-related conditions. Zonal isolation failure after primary cementing operations has often been attributed to the ineffective removal of drilling fluid filter cake. As early as 1940, large-scale displacement studies presented by Jones and Berdine2 discussed the difficulty of removing drilling-fluid filter cake from the face of a permeable formation. The studies concluded that a deposited filter cake was removed most effectively by scrapers, the hydraulic impingement of fluid jets, and acid treatments. Since 1940, the industry has spent millions of dollars studying the mud displacement process. Many industry-wide best practices have been established based on the results of this research. Even with these advances, some formations present significant challenges during drilling, primary cementing operations, and production or injection operations. These challenges often cannot be corrected when conventional best practices are applied. Sweatman et al.3 list the following challenges that the industry is currently facing:shallow water flowsgas- or water-cut drilling fluid and cementgas hydrates in the drilling fluidformation sloughing or hole collapse during drilling or open hole production