While assessing post-hydraulic-fracture perforation growth using solid-state, high-resolution acoustic imaging tools, it was noted that plug failures were occurring at a high frequency. Though plug failures can be observed from hydraulic fracture surface pressure and flowrate data, the aggregate frequency, causes, and severity of the resulting erosional damage at plug locations was not previously well understood and highly speculative. The sub-millimetric three-dimensional imagery generated from high resolution solid-state acoustic tools significantly improved the industry's awareness of plug failure frequency, mechanisms of failure, and the resulting impact to stimulation efficiency. These acoustic tools helped to uncover the causes and explore possible solutions to failing plugs. This paper presents aggregate data encompassing casing wall loss at over 2700 plug locations and presents emerging trends that appear across the broader dataset. In addition, this paper showcases the usage of high-resolution acoustic imaging in two operator-specific case studies.

A large collection of data recorded during coiled tubing (CT) operations has been analyzed using proprietary pattern recognition algorithms to identify downhole events with a high degree of confidence. These events include the drilling of plugs and stuck pipe incidents. Key performance indicator (KPI) metrics derived from this analysis provide insight into industry trends over time and by region, and can provide useful performance benchmarks for service providers and operator companies. Depth, weight and pressure data from multiple sources has been streamed and stored on a shared platform over a five year period, creating a record of over 39,000 data files. This data was processed to generate KPI-type statistics for over 500,000 detected plugs and 760 possible stuck pipe scenarios, based on analysis of depth and weight signatures. Using surface measurements to quantify downhole events has some limitations, but the method has proven sufficiently robust to allow useful trends to be observed and evaluated. While the analysis is confidential to the parties involved, a contributing company can compare their ‘performance’ statistics (as evaluated by the third party algorithms) against averages representative of the industry at large, arranged by year and geographic region, to identify areas of relative strength or weakness. An operator company can likewise compare metrics for different service providers (derived solely from jobs performed for their company) for those which elect to share data in this fashion. This paper presents statistics for plug drilling operations and stuck pipe incidents in North America between 2016-2020, a period of significant change in the CT industry. Examples show how average plug drilling times have generally decreased, with less frequent use of short trips and fewer pipe cycles. The data shows that, for some companies, faster operations have come at the expense of more frequent or severe stuck pipe incidents, whereas other companies have experienced fewer such problems. This comparative analysis illustrates how downhole outcomes can be deduced from surface measurements, and resulting performance metrics can vary widely between companies, fields and geographic regions.

A new coiled tubing (CT) failure mechanism has appeared in the past two to three years. The failures occur in CT strings used for frac plug milling in extend reach horizontal wells. The objective of this paper is to investigate a possible cause for these failures. The primary emphasis is analyzing the dynamic response of the CT to axial vibrations induced by a downhole extended reach tool [1], and the resulting tubing material response leading to failure.

Monitoring pipe corrosion is one of the critical aspects in the well intervention. Such analysis is used to evaluate and justify any remedial actions, to prolong the longevity of the well. Typical corrosion evaluation methods of tubulars consist of multifinger caliper tools that provide high-resolution measurements of the internal condition of the pipe. Routinely, this data is then analyzed and interpreted with respect to the manufacture's nominal specification for each tubular. However, this requires assumptions on the outer diameter of the tubular may add uncertainty, and incorrectly calculate the true metal thicknesses. This paper will highlight cases where the integration of such tool and electromagnetic (EM) thickness data adds value in discovering the true condition of both the first tubular and outer casings. These case studies demonstrate the use of a multireceiver, multitransmitter electromagnetic (EM) metal thickness tool operating at multiple simultaneous frequencies. It is used to measure the individual wall thickness across multiple strings (up to five) and operates continuously, making measurements in the frequency domain. This tool was combined with a multifinger caliper to provide a complete and efficient single-trip diagnosis of the tubing and casing integrity. The combination of multifinger caliper and EM metal thickness tool results gives both internal and external corrosion as well as metal thickness of first and outer tubular strings. The paper highlights multiple case studies including; i) successfully detecting several areas of metal loss (up to greater than 32%) on the outer string, which correlated to areas of the mobile salt formation, ii) overlapping defects in two tubulars and, iii) cases where a multifinger caliper alone doesn't provide an accurate indication of the true wall thickness. The final case highlights the advantages of integrating multiple tubular integrity tools when determining the condition of the casing wall. Metal thickness tools operating on EM principles benefit from a slim outer diameter design that allows the tools to pass through restrictions which typically would prevent ultrasonic scanning thickness tools. Additionally, EM tools are unaffected by the type of fluid in the wellbore and not affected by any non-ferrous scale buildup that may present in the inside of the tubular wall. Combinability between complementary multifinger caliper technology and EM thickness results in two independent sensors to provide a complete assessment of the well architecture.

In recent years there have been a significant number of coiled tubing (CT) failures during frac-plug drill-out operations. These failures occur most often when an axial vibration/pulsation extended reach tool (ERT) is included in the bottom hole assembly (BHA). There are significant efforts in the industry to first understand and then mitigate these failures. This paper examines the dynamic axial vibrations caused by these tools, and how these vibrations are amplified in the wellbore, possibly causing the material damage that later causes the failures. In some cases, these amplified vibrations have damaged surface equipment.

Drillpipe wear is a concern of operators when the tubular and/or the main bore of the well will be reused, for example in a sidetrack, or when the casing will be pressure tested. Drilling of long reach wells also creates a surface or intermediate casing wear problem. The fear of possible casing wear dictates the location of gas lift mandrel, which greatly affects well production and productivity. The objective of this paper is to show how downhole measurements have been compared with surface measurements of casing thickness to validate their use on casing wear models. Downhole tubular thickness measurement with ultrasonic tools is a well-known technique that has been used for many years in the oil and gas industry. The use of such downhole measurements varies from calculating burst/collapse rating to validating tubular integrity for reuse. These ultrasonic thickness measurements are done by computing the resonant frequency of the casing azimuthally in several samples sized around 1 in., then converting the resonant frequency to a thickness using known art and/or proprietary algorithms. The casing thickness can also be measured in a surface laboratory. The thickness of newer casing is measured in the laboratory to confirm its specifications and create a baseline. Similar measurement can also be done on retrieved casing to inspect their well and verify wear prediction models. The surface measurements are of much higher resolution and azimuthal sampling than a downhole measurement tool. The results of downhole thickness measurements and those of surface thickness measurements performed in a laboratory facility are compared and will be presented. The study highlights the match between the two types of measurements, the impact of a-priori knowledge of steel velocity, and comparing the log calculated burst pressure ratings to an actual laboratory measurement on joints. These joints have both downhole and surface measurements. When the tubulars are manufactured with corrosion resistant alloys, the steel acoustic properties deviate from the standard steel which the downhole measurements are based upon. The difference on acoustic velocities of the materials will be reflected on the thickness measurements of both downhole ultrasonic tools and surface laboratory measurements. Whereas surface laboratory measurements can be calibrated in-situ, downhole measurements need a priori knowledge of the acoustic properties. This paper describes the range of acoustic properties and how they affect the log derived thickness. Also, the accuracy of the downhole measurement is compared with the surface measurement when the steel properties are known

According to literature, most failures of coiled tubing are classified into four kinds of causes, mechanical damage, corrosion, string manufacturing, and human error. Among these, the failures due to mechanical damages take 29% of all failures. Although there are various kinds of mechanical damages, longitudinal plowing marks (LPM) are the major mechanical damages, account for 46%. Understanding the mechanism of LPM damage on coiled tubing surface will help to reduce this kind of damage. A conjecture is proposed that the running of the CT-gripper block-chain system will produce a period excitation which arouses CT string system resonance, and the vibration of CT string may make slippage between the gripper blocks and CT string at the wave peak and stop slippage at the wave trough, which may form fish scale damage. Because of the mismatch of the diameters between CT with grown diameter and gripper blocks, the first principle stress on the surface of CT will be large enough so that rock debris can carve CT easily when a gripper block is clamping it. FEM is employed to calculate the stress of CT when it is in this situation. The results verify the guess. To determine the CT string system resonance, we tried to find which gives the system a period excitation and how the system resonates. First a mechanical model of CT-gripper-chain is build, and excitation frequency is found to be related with the velocity of CT string running and length of gripper block. After idealization, a dynamic model for CT string in vertical well is built, and the wave equation is established, then frequency equation is derived and natural frequencies are found. After that, finite difference method is used to conduct numerical calculation. The results show that when system resonates, it must take minutes to reach large stress amplitude of the CT string enough to make damage on it. The field recorded data indicate that there maybe exists resonance actually. After synthesizing the information above, an image of the process how LPM is formed has been constructed. Finally, the measures to reduce LPM damage are recommended.

A new family of 2 1/8-in. wireline tractor and intervention tools has been developed to enable logging and intervention services in high-temperature deviated or horizontal wells while providing high power levels and maintaining excellent surface communication over long cables. In many horizontal or highly deviated wells, wireline tractors are a cost-effective solution for conveying logging tools, perforating guns, and intervention tools in comparison with other conveyance options such as coiled tubing. However, performing these logging and intervention services has become increasingly challenging, as well lengths increase and well temperatures rise. Providing the necessary high-power levels and maintaining real-time communication with the wireline tractor, payload, and other conveyed services from surface as operating conditions deteriorate are also problematic. Difficult operating conditions can be sustanined exposure to high temperature, long lossy logging cable, or combination of both. We assessed these challenges in developing key electronic, firmware, and software technologies for the new tractor and tools. To achieve robust tractor operation at high temperatures, the electrical hardware is designed to withstand operating temperatures of up to 180°C while minimize heat generation. Temperature sensors are placed throughout the tool to monitor system health during operation. Surface-downhole telemetry is optimized to ensure compatibility with long cables. The tool algorithm was developed to maximize mechanical power delivery based on operating conditions. Results are presented from lab-based system level integration tests of the 2 1/8-in. wheeled tractor and intervention tools at temperatures of up to 175°C and delivering more than 1 kW of power on 30,000 ft of logging cables while maintaining communication with the payload. The technologies described in this paper allow the 2 1/8-in. wireline tractor to perform high power interventions and logging while tractoring in wells previously inaccessible due to depth or temperature constraints.

A cement barrier in an oil well is intended to prevent any movement of fluid along the wellbore. If there is movement of fluid, acoustic energy will be produced and may be detected by a suitably sensitive sensor. This paper describes the controlled testing and real world application of a new passive acoustic tool and the benefits it brings to evaluation of even very small fluid migration issues. Traditional methods of cement analysis rely on evaluating the placement and condition of a cement barrier, which may confirm the presence of cement behind the casing or liner. There are innumerable examples of cemented annuli that exhibit sustained annular pressure at surface – an indication of fluid migration from a charging source downhole – despite a good cement condition log having been acquired. In such cases there will be acoustic energy generated by the movement of even small amounts of fluid, the presence of which may be used to indicate a failure of performance of the cement. A number of test cells were used to recreate realistic downhole scenarios of fluid flow, the cases including free-pipe, a single small channel, an exterior micro-annulus and "good" cement. The sealing performance of the annular barrier was tested against both gas and liquid over a range of flowrates and pressure differentials to best simulate the downhole environment. Reliable detection of annular flow at rates as low as 0.03 litres per minutes was recorded for liquid, while gas migration was detectable even at very low differential pressure. The latter case is of great interest in wells planned for permanent abandonment where even slow annular pressure build-ups are unacceptable. A logging campaign covering 8 wells was subsequently performed; rig-less and with production tubing still in place; to identify the source of B-annulus charging. The new technique was able to successfully identify areas of gas migration in each of the wells allowing detailed planning to be conducted prior to bringing in a rig. The analysis of cement from the perspective of absolute performance as opposed to the traditional approach investigating the condition allows very detailed analysis of well barriers. This is especially useful in operations for permanent abandonment of wells were any leakage is unacceptable. The ability to map the fluid migration from source to surface is a powerful tool in the efficient design of remediation programs.

As a result of many industry efforts, the premature fatigue failure of undamaged coiled tubing (CT) strings is almost negligible. However, despite the current understanding and control of low-cycle fatigue, CT string failures remain present in the industry. Several prior technical publications reviewed the causes and trends of CT string failures that occurred within the period of 1994 to 2005. This paper will review CT failures mechanisms and trends as observed over the last twelve years and compare them to the prior ten years period. It will also review the new failure mechanisms that have appeared with more challenging operational conditions and the associated actions taken to reduce their influence. Within one major service company, all failures that occur are analyzed for the root cause(s) of failure. This results in the identification of corrective actions to avoid their recurrence. Statistical data is kept to observe trends on failure causes. Several technical publications show that approximately 80% – 90% of CT string failures within the period of 1994 to 2005 were associated with corrosion, mechanical damage, human error, and string manufacturing problems. Actions taken in the last two decades by the CT services companies, and constant improvement implemented by CT manufacturers have reduced the influence of some of these causes. However, work in ever-more challenging well conditions (such as higher pressures, temperatures, and depths), the need to use larger-diameter and higher-strength CT, and the use of recycled fluids for the interventions, have created new issues and introduced new CT failure mechanisms. The new mechanisms within the industry include: microbiologically influenced corrosion (MIC), premature fatigue failures on bias welds of high-strength grades, and mechanical damage associated with pipe slippages. This paper will compare the failure trends reported for the period before 2005 with the trends observed for this service company within the period of 12 years after 2005 (i.e., from 2006 to 2017). The changes in the failures trends are analyzed, and examples of the newer CT failure mechanisms and the mitigating actions taken are presented.

Among different industries, there is a lack of consensus with regard to wireline initiation safety with explosives. In the oil industry, procedural methods, such as electrical before ballistic arming (EBBA) and safety keys, have been used successfully for many years. However, the industrialization of fracturing has increased the volume and speed of the operations, and it is now common to have new hazards, such as multiple radio frequency (RF) sources and electric fracturing equipment. This work attempts to clarify wellsite safety requirements and proposes new solutions. RF radiation can create accidental detonation of an electro-explosive device (EED), which can be catastrophic if the device is connected to a wireline perforating gun. Strict adherence to safety procedures including radio silence during perforating jobs and other controls have mitigated most RF risks. Perforating safety standards are being updated at the writing of this paper with a major overhaul of the current API RP67 Recommended Practice for Oilfield Explosives, second edition(API 2007, reaffirmed 2015), including a third classification for primary-explosive-based detonators with enhanced RF protection. The explosive manufacturers and service companies are aware of this trend and are developing new products to add engineered controls for the hazards. As the market transitions from procedural to engineered solutions, competing claims and counterclaims make it difficult for end users to understand the risks. This will continue until effective engineered controls become common and best practices in the industry are adopted.

Impact of CO 2 corrosion on well integrity is an issue in mature fields of Colombian foothill wells. Concerns in regard to corrosion of casing strings having access only through the existing 7" completion challenged the use of new technology to achieve both: log corrosion on outer strings and do not suspend the well to get a full column of fluid. Therefore, corrosion monitoring was performed through 7" chrome production tubing with a new Electromagnetic Scanning Tool (EMST), in a challenging scenario: shut-in well with 3 outer casing strings with a gas cap in the upper wellbore. The job objectives were first to test the technology to detect metal loss from the outer casing strings as well as loss both inside and outside of production tubing (without pulling the production tubing) and second to establish a base line for future corrosion analysis after the immediate drilling rig intervention for sidetracking. A careful candidate selection was performed based on criticality for CO 2 corrosion, completion design, service years and operating status of the well including consequence analysis to get a pilot well for EM logging. In production since 1998, the BA Y16 well was selected to be logged before a thru tubing deepening to reach two other reservoirs and further service conversion from oil producer into a gas injector well; the EMST was run in Q1 2013 and measuring the cumulative thickness up to three strings determining that no external corrosion was present in particular in the section of interest, also the high resolution image showed no presence of internal corrosion. Therefore, a successful operation was achieved meeting the proposed objectives with no HSE incidents and within budget. This technology is proven and has become a solution for further wells where CO 2 or bacteria damage has been evidenced including corrosion mapping through chromed and carbon steel in a single run avoiding the excessive costs related to pulling the completion to get access to the outer casing strings.

Near-wellbore (NWB) stimulation continues to evolve and change over time as a wide variety of tools and processes designed to target this problem area of the borehole are being developed. Fluidic oscillators (FOs) are amongst some of the most simple and successful tools to affect this region; however, even after decades of multidiscipline industry development, there is still room for improvement. This paper discusses the search for the perfect oscillator design for NWB stimulation using solid modeling and 3D computational fluid dynamics (CFD). These tools allowed fast and efficient evaluation of hundreds of concepts to optimize features of the selected design without the need for prototype testing during each design iteration. As a result, many months of development time were saved by eliminating repeated manufacturing and testing activities. The best possible solution was then validated in the laboratory using rapid-prototype models, machined prototypes, and ultrahigh-speed photography. The main purpose of this paper is to focus on the case histories collected during field testing and commercialization of the new design. Pre- and post-treatment production figures, infield well comparisons with competing technologies, and repeat treatments originally performed with previous versions best showcase the superior performance from the advances made to the tool and treatment process and are used whenever possible. The results prove what laboratory testing predicted—the improvements translated to superior stimulation results.

Wellbore obstructions are a common dilemma and typically must be removed as they can severely restrict a well’s production capability and have proven to be very costly. For instance, scale formation will eventually result in lower yields and well failure, while a fish left in a well can hamper future wellbore operations. The thru-tubing well intervention impact hammer was designed to dislodge fish or scale from a wellbore, by delivering an upward or downward impact force. The tool is activated by flow, in combination with compressive or tensile force, depending on the required impact. In operations that require bi-directional forces, both the single-acting up (SAU) and single- acting down (SAD) can be used concurrently on the same bottom-hole assembly (BHA). This paper describes the performance of "fluid activated impact hammers" for fishing operations. Case histories of recent field results are also discussed which illustrate the efficient removal of wellbore obstructions in deviated wells. This enables the well to be put back on production quickly and saves cost. The impact hammers are utilized in various applications, such as shifting sleeves, shearing pins, breaking disks, assisting with fishing operations and scale removal; in fact, any application where high frequency localized impacts are required. The tool’s impact force can be adjusted to accommodate the specific parameters of an operation. Its maximum capacity is up to 80,000 lb (36,000kg) per impact depending on tool size. The impact hammers enable operators to cost-effectively remove a wireline-retrievable packer (WRP), where conventional wireline techniques have failed and jars had proved impractical. The design allows adjustment of the impact force by manipulating the tension or compression weight on the tool. This maximizes operational efficiency, by enabling the impact hammer to function in numerous situations and the individual up and down hammer components enable the BHA design to accommodate specific jarring direction.

Abstract Vortex-induced vibration (VIV) of tubings and pipings is of practical interest to oil industry. When VIV occurs to pipes, it induces alternative stress thatwhich would results in the reduction of pipe fatigue life. The objective of the paper is to investigate VIVs in tubings or pipings with non-linear geometry. This paper categorizesd the occurrence of cross-flow and in-line VIVs of pipes based on flow directions and pipe orientations. The complexity of VIV for pipes with non-linear geometry, as compared to straight pipes, is demonstrated. We devised a scheme to incorporate power balance principal into finite element method (FEM) to analyze the cross-flow VIV for tubings and pipings with non-linear geometry. A main feature in our approach is the modeling of lifting forces (excitations) and hydrodynamic damping in FEM. At present stage, most commercial VIV packages mainly deal with risers or pipelines that are either straight or with large radii, and they only considered curvature component associated with the cross-flow direction of the flow (d.o.f.), that is the (i.e., the direction perpendicular to the flow velocity). Stress calculation near the bends and elbows of the pipes, is not accurate. Our approaches, on the other hand, consider the responses in all 6 d.o.f of each element along the pipes and it is a truly three dimensional vibration analysis. Our approach provides an alternative to complement the existing method for solving the VIV problem for tubings and pipings with highly non-linear geometry. 1. Introduction The highly specialized subject of vortex-induced vibrations (VIVs) is part of a number of disciplines, incorporating fluid mechanics, structural mechanics, vibrations, computational fluid dynamics (CFD), acoustics, wavelet transforms, complex demodulation analysis, statistics, and smart materials. They occur in many engineering situations, such as bridges, stacks, transmission lines, aircraft control surfaces, offshore structures, thermowells, engines, heat exchangers, marine cables, towed cables, drilling and production risers in petroleum production, mooring cables, moored structures, tethered structures, buoyancy and spar hulls, pipelines, cable-laying, members of jacketed structures, and other hydrodynamic and hydroacoustic applications. One stimulus for a resurgence of interest in VIV came from the oil service companies foras the requirement of sustainable drilling equipments for use in to sustain in a deeper ocean and hurricane environments. and as the sea state along the depth of the ocean was found to be vehement in a hurricane. Previous efforts in VIV in the offshore systems are mostly devoted to risers or free spanned pipelines with large radii of curvature. In contrast to previous work, this paper analyzes VIV for tubings or pipings with non-linear geometry. The tubings and pipings analyzed in this paper consists of horizontal, inclined, and vertical sections which are in the same plane. This paper categorizesd the occurrence of cross-flow and in-line VIVs of pipes based on flow directions and pipe orientations. The complexity of VIV for pipes with non-linear geometry, as compared to straight pipes, is demonstrated. We incorporated power balance principal into FEA to analyze the vibrational amplitude and stress for the tubings and pipings. A main feature in our approach is the modeling of lifting forces (excitations) and hydrodynamic damping in FEM. What distinguishes our approach from that of commercial VIV packages [1] is the absence of using piping modal curvatures in the prediction of the stress along the pipings. Most commercial VIV packages mainly deal with risers or pipelines that are either straight or with large radii, they only considered curvature component associated with the cross-flow direction of the flow (i.e., the direction perpendicular to the flow velocity). Stress calculation near the bends and elbows of the pipes, is not accurate. Our approaches, on the other hand, consider the responses in all 6 d.o.f of each element along the pipes and it is a truly three dimensional vibration analysis. The structure of this paper is as follows. Section 2 discusses the occurrence of VIV to pipes with nonlinear geometry. The occurrence of cross-flow and in-line VIV is categorized based on flow directions and pipeline orientations. In section 3, the amplitude prediction scheme of power-balance, previously used in riser VIV analysis, is applied to pipings with nonlinear geometry. In section 4, the incorporation of the power-balance principal in FEM is devised and demonstrated using an example. Results from the amplitude prediction scheme and FEM are compared. The analysis is preceded in section 5 with SHEAR7 implementations of VIV in nonlinear pipings together with comparisons and discussions of results from FEM and SHEAR7. Conclusions are drawn in section 6.

Abstract In coiled tubing conveyed through-tubing fishing operations, conventional jarring technology often creates limitations due to the requirement to repeatedly cycle the coiled tubing over the gooseneck in order to actuate and re-cock the jar. It is well known and documented in our industry that this repeated cycling leads to pipe fatigue and coiled tubing life reduction. Additionally, the low frequency, high-impact of the jarring assembly, may in some cases cause the fish to become wedged tighter. Vibratory and high frequency impact tools have been found to provide operational and economic benefits over hydraulic, time delayed jarring tools in a variety of through tubing fishing and workover applications, particularly in horizontal and extended-reach wells. As opposed to jars, vibratory type impact systems are capable of delivering significant impact forces at the fish with only limited set-down weight or over pull available making them particularly well suited to the constraints of coiled tubing operations. These hydraulically powered systems are configured to deliver downward impacts in compression and upward impacts in tension. Both downward and upward impacts are achieved without the necessity to cycle the coiled tubing between impacts, therefore significantly reducing low-cycle pipe fatigue. Additionally, when a fish is stuck in sand or debris, temporarily suspending or liquefying sand particles by lighter high frequency blows as delivered by an impact tool while over pull is applied offers a higher degree of success in freeing the fish. This paper will outline the uses and advantages of down-hole high-frequency vibration technology from a coiled tubing perspective and also describe the development and laboratory testing results of a new, modular vibratory impact tool offering a significantly reduced operating length yet delivering greater impact thus increasing the operating envelope for such tools adding demonstrable value to a variety of coiled tubing fishing and workover operations. Introduction It is well known that coiled tubing generates greater force pulling rather than pushing. If the coiled tubing does not generate enough force (either up or down), force assisting tools can be included in the workstring. In today's horizontal and extended reach wells, conventional jarring assemblies are not always an option for retrieving or shifting downhole devices on coiled tubing. Contrary to jars, vibratory and high-frequency impact tools are capable of significant impact forces with limited set down weight or overpull available. High frequency impact tools have been used in the industry for quite some time now, providing operational and economical benefits. For the purposes of this paper "frequency" is discussed as a relative term. Low frequency is used to describe approximately 1 to 2 blows per minute and high frequency describes approximately 1200 to 3600 blows per minute, equal to 20 to 60 blows per second (Hz). When running jars on coiled tubing, the pipe has to be cycled over the gooseneck multiple times to fire and re-cock the jar, whether in the up or down mode. Repeatedly cycling the coiled tubing can result in fatigue of the pipe section that is traveling up and down over the gooseneck. This can often be a limiting factor in the fishing job. In some cases, the low-frequency, high impact blows of a jarring tool can also be a limitation. A sand stuck fish is often wedged tighter after the combination of hard jarring with small particles. If the sand particles are temporarily suspended or liquified by lighter, high frequency blows while overpull is applied, there is a much greater chance of freeing the fish. The high-frequency impact tool can deliver both upward and downward impacts without cycling the coiled tubing.[1] Vibratory and high-frequency impact tools are typically used for shifting sliding sleeves, fishing, swaging collapsed tubing, breaking knock-out isolation valve discs and setting and retrieving wireline tools in deviated wells. Some high-frequency impact tool designs include a rotational option in the down mode for "impact drilling" applications. The most common applications of the impact drill include scale milling, hard-cement milling, resin-sand removal and gravel removal.

Abstract 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.

Abstract A study has been performed to determine the technical and economic feasibility of using an electric drilling motor to drill open hole with coiled tubing. An historical review of electric motor drilling was performed, a conceptual design was developed and a market analysis was performed. This paper summarizes the findings from this study. For more details on this study see reference 1. Introduction Using coiled tubing (CT) to drill open hole was first attempted in Canada in the 1970's. In 1991 the first recent CT drilling (CTD) experiments were performed. Since 1991 there has been a tremendous interest in this drilling technique, with more than an estimated 300 CTD operations being perfonned in 1995. The continuous tubing used for CT is bent when it is spooled on and off of the reel. The fatigue damage that occurs in the CT due to this repeated bending will eventually cause the pipe to fail. As the diameter of the CT increases the fatigue damage increases and thus the expected life of the tubing decreases. Although CT is being built as large as 4.5" in diameter, the "fatigue life" limits the practical diameter for drilling to 2 3/8". Limiting the CT diameter limits the hole size that can be drilled with CTD which causes CTD to become a subset of slimhole drilling (SHD).