Coiled Tubing String Research Articles

Underbalanced Coiled Tubing Drilling: Delivering Well Production Safely in High H2S and Tight Gas Reservoirs, UAE

Summary United Arab Emirates (UAE) is seeking to become self-sufficient in gas supply by 2030. This has led the country to initiate several exploratory and appraisal projects to achieve this goal. This study covers one such pilot project targeting production from tight gas reservoirs in three wells through a coiled-tubing (CT) underbalanced drilling (UBD) project in ADNOC Onshore. CT pressure control equipment (PCE) was rigged up on top of production trees with wells already completed and cemented. A CT tower was used to accommodate the drilling bottomhole assembly (BHA) and eliminate risks related to its deployment. CT strings were designed to reach target intervals with sufficient weight on bit (WOB), suitable for sour environments, and able to withstand high pumping rates with mild circulating pressures. To address the hazards of H2S handling at the surface, a custom-fit closed-loop system was deployed. The recovered water was treated on the surface and reused for drilling to decrease the water consumption throughout the operations. The plan was to drill 3 3/4-in. horizontal laterals in all candidate wells. Each well was completed with a combination of a 4 1/2-in. and a 5 1/2-in. tubing and a 7-in. liner. Five laterals were drilled across the three candidate wells targeting carbonate reservoirs with each lateral having an average length of ~4,000 ft. The achieved rates of penetration varied significantly from 15 ft/min to 30 ft/min while drilling through the various formations. Over the course of the pilot project, several challenges had to be addressed, such as material accretion on the CT string during wiper trips, treatment of return fluids having high H2S content and rock cuttings, and ensuring the integrity of the CT pipe while operating in severe downhole environments. Solutions and lessons learned from each well were implemented subsequently in the campaign, such as the use of increased concentrations of H2S inhibitor to coat the CT string, the use of nitrified fluids based on changing well parameters to maintain underbalance, thorough pipe management through real-time CT inspection, and adding a fixed quantity of fresh water to the drilling system every day to avoid chemical reactions between the drilling fluid additives and hydrocarbons. The wells completed with this method exceeded production expectations by 35–50% across the project while reconfirming the value of the technology. The use of CT for UBD is still considered a challenging intervention worldwide. Such cases in high H2S environments are rare. This study outlines best practices for a CT UBD and a setup that can be replicated in other locations to implement this methodology with high H2S and when rig sourcing is a concern.

HYDRAULIC COILED TUBING TRACTOR TECHNOLOGY EXTENDS THE ACCESSIBILITY OF COILED TUBING IN HORIZONTAL WELLS, ALLOWING BETTER WELL INTERVENTION – CASE STUDY

Recent advances in drilling technology have resulted in longer horizontal wells and have increased the complexity of well completion; the well intervention is becoming more challenging. Conventional techniques are no more adequate to access in long openhole horizontal sections when using coiled tubing to perform intervention works such as stimulations, logging and zonal isolation. This essay was created to assess the capability of a coiled tubing string to reach the desired depth in a projected long horizontal well. The scope of this essay is to provide a complete set of simulations to predict the tubing forces for two proposed different diameters of openhole section. Such simulations can serve as guidelines for completing the well.

Coiled Tubing Program Succeeds in Harsh-Environment Tight Gas Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209032, “Successfully Adapting and Overcoming Challenges for Coiled Tubing Applications in High-Pressure Sour Environments and Horizontal Unconventional Tight Gas Wells in UAE,” by Ole Sorensen, Yang Wu, and Didier Caillon, SPE, TotalEnergies, et al. The paper has not been peer reviewed. During the completion phase of four unconventional wells in the United Arab Emirates, a detailed engineering approach overcame challenges presented by extreme conditions of pressure, temperature, and a sour environment across long horizontal sections to carry out cleanout activities successfully. This operation, the first of its kind in the country for the operator, yielded lessons for design considerations and the execution process and recommendations for coiled tubing (CT) intervention in similar working environments. It also confirmed that 110,000-psi-yield-strength quench-and-tempered (Q&T) CT strings can be deployed safely in a high-pressure sour environment by implementing proper risk-mitigation strategies. Introduction The unconventional gas play (referred to as “A” in the complete paper) featured a reservoir pressure of nearly 13,000 psi and a bottomhole temperature of approximately 325°F. The environment was sour, with 5 mol% of hydrogen sulfide (H2S) and 5% carbon dioxide (CO2). The well’s architecture consisted of a 5½-in. monobore completion with cemented casing and horizontal sections ranging from 5,000 to 8,200 ft. The selected completion methodology was plug-and-perf, including up to 35 fracturing stages in a single well. Overview of CT Intervention Challenges The true vertical depth of the play was 12,600 ft on average, representing a maximum anticipated surface pressure (MASP) of 8,000 psi with the wellbore full of working fluid (8.34-lbm/gal slickwater) and a maximum potential wellhead pressure (MPWHP) of 11,300 psi with the wellbore full of gas. Also, partial pressures of H2S and CO2 exceeded 600 psi at bottomhole conditions, confirming that sour- and corrosive-service programs had to be implemented fully in this project. Convergence of MASP above 7,500 psi, CT dynamic pressure of greater than 11,000 psi, lateral length of up to 8,200 ft, and the sour and corrosive environment required a highly engineered approach on the design and selection of the CT string and configuration of the surface equipment.

New String Deployment Concept Extends Operational Limits for Megareach Interventions

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22577, “Extending the Operational Limits To Target Megareach Interventions With Coiled Tubing: A Study of the First 40,000-ft-Long CT String Deployment Using Uniquely Engineered Energy Transportation Solutions,” by Karan Kaul, Nicolas Dupouy, and Jose Jimenez, Halliburton, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. An operator requiring an offshore coiled tubing (CT) intervention into 40,000-ft-deep wells from artificial islands of the United Arab Emirates encountered challenging crane and transportation limitations to lift a 2⅜-in. CT reel weighing approximately 200,000 lbm. This, combined with a desire to improve operational efficiency in moving from well to well and eliminating large mechanical lifts, led to the design of a custom-engineered transportation solution for the large-diameter, heavy CT spool. Introduction CT and its associated setups are in high demand for wellbore intervention to perform operations such as valve or sleeve shifting, pinpoint stimulation with custom chemistry, milling, fishing, wellbore diagnostics using fiber optics, and drilling with different downhole tools. These tasks become even more challenging when difficulties associated with extended-reach maximum-reservoir-contact reservoirs are considered. While the term “extended-reach” refers to wells for which the measured depth (MD) is greater than twice the true vertical depth (TVD), the term “megareach” refers to wells for which the MD is greater than three times the TVD. A CT string is a continuous string of pipe manufactured from a specific grade of material determined by the downhole application for which it is intended. It is coiled over a drum (referred to in the paper as a spool) with more than 25 full layers around the bed wrap and has a high amount of energy stored in it because of the residual bending of the CT material. Although the string is secured at the end with an industry-specific clamp, close monitoring is required to avoid loosening from vibrations caused during transportation. After storing the CT pipe on the spool, the spool usually is shipped and transported from the shore jetty to the artificial island jetty using a conventional vessel. It is then offloaded, lifted, and secured onto a CT drive reel using a regular crane ready for wellsite operations (Fig. 1).

Best Practices for Avoiding Erosion in Annular Fracturing

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 204417, “Avoiding Erosion: Best Practices for Coiled Tubing Annular Fracturing Operations,” by Kaveh Yekta, SPE, and Jamie Fenwick, SPE, Essential Energy Services, and Kevin Elliott, SPE, NOV, et al., prepared for the 2021 SPE/ICoTA Virtual Well Intervention Conference, 22–25 March. The paper has not been peer reviewed. The onset of erosion of coiled tubing (CT) strings may be difficult to predict in annular fracturing operations. The complete paper describes a methodology of verifying that CT strings have not been subject to erosion caused by annular fracturing operations. An exploration of pumping rates used on these strings in operations also provides field-tested practical guidelines for avoiding erosion when performing annular fracturing jobs. Inspection A CT string may be exposed to erosion in the outer surface during CT annular fracturing operations. The critical parameters that may influence the magnitude of erosion include fracturing pump rate, sand concentration, fluid rheology, wellbore geometry, and the grade of CT string. One measurable parameter to examine the string’s suitability is the wall thickness for each section. The CT strings discussed in the complete paper were sent for inspection to learn about the effect of the fracturing treatment. A series of nondestructive tests was conducted pre- and post-operation to evaluate the readiness of strings for subsequent operations. The complete paper includes two graphs related to the results of these tests. Materials The API 5ST specification requires using eddy current (EC) inspection for CT. With respect to API 5ST, quenched and tempered tubing had not been addressed at the time of this paper’s submission, so it is not clear whether the CT manufacturers employ EC techniques after quenching and tempering. However, it is expected that all tubing will be subject to EC inspection at least before any quenching and tempering operations. Inspection methodology and equipment consistency is important to establish a baseline inspection necessary for subsequent comparisons. In the case of the CT strings used in this study, all were subject to EC inspection at tubing manufacturing and then subsequently inspected by an outside, third-party vendor using magnetic flux leakage (MFL) technology when spooling the strings on the unit. No known third-party EC vendors can inspect string lengths of CT, so MFL inspection is the only available solution. Photographs of CT inspections taken at the manufacturing facility and the service and distribution point are included in the paper. Several commercial third-party inspection companies operate in North America, where this work was performed. Provided that the inspection can begin by identifying features in the calibration standard (often a through-drilled hole), the selection of inspection methodology is primarily a matter of preference for the service company and operator.

Customized Solutions for Coiled Tubing Interventions in the Bolivian Sub-Andean Basin

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202620, “A Review of 25 Coiled Tubing Well Interventions: Customized Solutions for Bolivian Sub-Andean Basin,” by Jovanny A. Hernandez, SPE, Luis F. Antelo, SPE, and Carlos D. Rodriguez, Halliburton, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Fields in the Bolivian Sub-Andean Basin are remote and difficult to access. The producing zones include the country’s most challenging wells, with depths of up to 26,000 ft, with high pressure/high temperature (HP/HT), high gas cut, crossflow, dogleg severity, and well-access restrictions. The complete paper reviews 25 coiled tubing rigless well interventions (CTRWI) to extend the life of those wells, including operations involving nitrogen (N2) lift, acid wash, milling, shifting sleeves, setting packers, stimulation, velocity strings (VS), and fishing. Introduction CTRWI in Sub-Andean Basin fields had not been implemented historically because of limited road access to the fields, lack of available equipment with high technical capabilities, high pressure, and well depth. Beginning in 2017, however, operators evaluated the risk and elected to perform CTRWI involving stimulation, cleanout, N2 lift, fishing, VS jobs, and other techniques. Equipment with specialized capabilities was requested to address the operational requirements and the ability to travel on the remote roads while respecting transit regulations limiting maximum weight to 55 tons. The challenges to transporting equipment economically include - Transportation of large reels of 2⅞-in. coiled tubing (CT) string to complete dual-sectioned VS installations - Transportation of CT unit with 6,600 m of 1¾-in. CT string (weight of less than 55 tons) - Continuously moving large volumes of N2 to the field Wells in these fields were drilled no more than 10 years ago. The majority were built with smart completions, several production layers separated with swell packers and flowing through sliding sleeves configured with the same direction of actuation for opening and closure. Completions are configured with production tubing sizes of 7, 5, 4½, and 3 in. The tubing and accessories are made from chrome 13 because of the presence of carbon dioxide in the production fluids. The region includes some exploratory fields having HP/HT conditions and mature fields with declining production. These wells are important for both the operators and the local government because their production represents more than 50% of national production. On-Site Laboratory Testing Characteristics of produced formation water and mineralogy tests of water samples helped identify a calcium carbonate (CaCO3) scale type. Because CaCO3 scale is known to be acid-soluble, a tailored acid-treatment system was selected with a static formation temperature between 220 to 286°F. On-site laboratory tests using a combination of 13% acetic and 9% formic retarded acid treatment systems were applied to the samples obtained, and results of a solubility test were observed. The selected treatment was demonstrated to be highly effective at dissolving CaCO3 scale according to the test made at the wellsite. High confidence was placed in the test results of the acid-treatment sample because dissolution was above 85% in a 4-hour test period under static well temperature.

Low-Force Shear Blades Developed for High-Strength Coiled Tubing

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204403, “Development of Low-Force Shear Blades for High-Strength Coiled Tubing,” by Scott Sherman, Nexus Energy Technologies, prepared for the 2021 SPE/ICoTA Virtual Well Intervention Conference, 22–25 March. The paper has not been peer reviewed. As coiled tubing (CT) grades have evolved during the past 20 years and wall thicknesses have increased, the resulting force required to shear coil has more than doubled. An industry need existed to develop a shear blade for blowout preventers (BOPs) that could cut high-strength CT using legacy pressure-control equipment already in use. The paper describes the iterative process of development of a novel shear blade able to cut high-strength CT with 50% of the normal shear force. Objective The objective of the work detailed in the complete paper was to develop a novel CT-shearing system capable of cutting high-strength heavy-wall CT with reduced hydraulic pressures. Considering that CT will continue to evolve in terms of yield strength, the goal of the study was to future-proof BOPs wherever possible to protect customers from the liability of obsolete equipment. The authors write that, ultimately, BOPs will need to cut 175-grade CT strings with a 7-mm wall thickness with 103 MPa of wellbore pressure and less than 17.2 MPa hydraulic pressure. Development Process Initially, the following five options were considered: - Larger-diameter cylinders. This seemingly simple option, which would generate more shear force, was ruled out because the implementation would not be backward-compatible with existing well-control equipment and the larger cylinder volume would result in slower cycle times. - Boosted actuators. These could double shear force while maintaining piston diameter. While this solution is simple, theoretically, these actuators require twice as much hydraulic fluid from the accumulator to function. This results in a closing time that is nearly double that of a nonboosted actuator. - Pressure-balanced actuators. With this option, hydraulic forces would not need to overcome the forces related to wellbore pressure in addition to providing sufficient force to shear CT. These actuators do increase the amount of shear force available to cut CT when used on high-pressure wells. However, they increase complexity, cost, and weight and could result in trapped wellbore fluids within the actuator that could lead to corrosion-related issues. - Increasing hydraulic pressure to a given set of rams using a pressure multiplier for the shear rams or a similar system. This solution was deemed unsuitable because the hydraulics of most BOPs are designed for 150% of their rated pressure. Doubling the hydraulic pressure available to the BOP could damage the hydraulic cylinders and associated actuators, resulting in a catastrophic well-control situation. - Modifying shear blade geometry to reduce the shear force needed to cut CT using existing equipment. This was selected as the most-logical approach because the modified shear blades could be retrofitted into existing BOPs. Furthermore, this solution would not require modification to existing wellsite equipment such as accumulator skids and would not increase the weight or size of the BOP stack.

Initial Residual Curvature Configuration of Coiled Tubing and Analysis of the Effect on Downhole Buckling Behavior

Summary This study discusses the development of a finite element analysis (FEA) model that describes the bending and straightening process of coiled tubing (CT) at the wellhead and the buckling process after CT is run in wells. On this basis, this study calculates the initial residual bending configuration quantitatively for the first time and describes the residual stress and strain-changing regularity. The initial residual bending configuration of CT under wellbore constraints after running into the hole is sinusoidal, which essentially affects the CT downhole mechanical behavior. Simulating the buckling process of the CT string in the vertical and horizontal sections with the CT string assumed straight served as control subjects. This study verifies the accuracy of the numerical simulation method by comparing the results of critical buckling loads to previous research results. The initial residual bending configuration significantly affects axial load transfer and reduces the least axial force required to produce a helical buckling in the wellbore. The residual stress induced by the bending and straightening process at the wellhead makes the buckling and buckling release of CT downhole an elastic-plastic process, whereas it becomes an elastic buckling process if the initial configuration of the CT string is assumed straight. The comparison between the buckling process of CT with residual bending and CT without residual bending shows that the effect of residual bending on CT cannot be ignored when studying the downhole mechanical behavior or job design.

Coiled Tubing Gas Lift Revives Dead Wells in South Pakistan

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper IPTC 19930, “Coiled Tubing Gas Lift: An Innovative Solution for Reviving Dead Wells in Southern Pakistan,” by Aizaz Khalid, Nestor Molero, SPE, and Ghassan Hassan, et al., Schlumberger, prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. This paper describes a coiled tubing gas lift (CTGL) technique successfully used to restart production from two pilot wells in a mature field in Pakistan that had been shut in since 2015. The project yielded production gains that resulted in a short payback period and verified that the technique represents an effective and economical solution to restart production in mature fields where conventional artificial-lift methods challenge well economics. The pilot results have encouraged the operator to further implement CTGL in Pakistan. According to the authors, suitable candidate selection, including data accuracy for nodal analysis and production forecast, and proper planning played fundamental roles in the project’s success. Introduction Exploration and production companies in Pakistan struggle with multiple challenges including pressure from regulatory bodies to increase oil and gas production to meet requirements of an energy-starved country in a period of historically low oil prices. With little new significant discovery, operators are challenged to produce economically from mature and declining fields. Several fields in south Pakistan have been forced to shut down because of uneconomical production rates. Most of the wells in these mature fields do not flow naturally because reservoir pressure is insufficient to overcome the hydrostatic column. Existing techniques have their own challenges, including very high associated costs. Realizing these challenges, the government of Pakistan recently prioritized developing mature fields and optimizing production in declining fields. Artificial-Lift-System Selection A detailed screening of candidate wells was carried out to identify innovative artificial-lift solutions. The deployment of gas-lift (GL) valves using coiled tubing (CT) soon emerged as the best option, offering the highest return in a cost-benefit analysis. CTGL is a rigless solution that enables setting GL valves at the required depth during any stage of a well’s life. CTGL strings can be installed without making permanent changes to already-existing wellbore tubulars, and make it easy to install in wells with either monobore or through-tubing completions. The technique allows gas to be injected through CT with production through the CT-to-tubing annulus. The system also is retrievable and replaceable when needed. Gas-lift mandrels (GLMs) and valves are added to the CT in a similar fashion to any traditional GL completion. A work-over rig is not required, and installation of the CT string also provides the opportunity to modify well cross-sectional flow areas, thus improving well hydraulics and production flow. Two flow configurations are possible: (a) tubing flow (i.e., production flow up the insert tubing string, gas injection down the newly created annulus) or (b) annular flow (i.e., gas injection down the insert string, production flow up the newly created annulus between parent tubing and the CT insert string).

Big Data vs. Diverse Data: Confidential Databases Lack Performance Benchmarks

Carlos Castañeda is hungry for more data and analysis from coiled tubing jobs, and the manager of coiled tubing engineering at Pioneer Energy Services said he also needs to know how his company’s work compares with the competition. Pioneer is one of more than 25 companies relying on CoilData for real-time monitoring. The data and analysis can tell him which of his people is efficiently drilling out plugs left after fracturing and the ones who may need retraining. What he does not have is a measure of how his company’s work compares with competing well-intervention companies because the data needed to do that are confidential. “If you are an individual service company, you are looking at your pipe in isolation,” said Paul Brown, the CEO and founder of CoilData. He sees great value in the data he has collected from more than 155,000 jobs monitored over the past 10 years, but tapping it will require companies to decide if the competitive advantage of analysis based on industry benchmarks exceeds the value of the current level of confidentiality. Recently he presented a rare multicompany look at how coiled tubing companies manage their most critical asset, coiled tubing strings. The paper presented at the SPE/ICoTA Well Intervention Conference and Exhibition showed significant differences in how much use companies got out of 3,700 tubing strings studied (SPE 194306). It raised the question: Are they leaving money on the table by prematurely retiring tubing strings that cost about $250,000 each? The Bigger Picture For those with no interest in well workover, it also raised a larger question about decision making. It showed how service company decisions vary widely when each company is operating in data isolation. Brown’s discussion of the results also showed how the available information on decision making can be limited and subjective. Brown has a unique perspective based on a career where he used his software and analytical skills to create tools to gather, monitor, and analyze well interventions. He offers many reasons for why companies stop using strings of coiled tubing. But the study showed a significant number of examples where the string’s cumulative metal fatigue—an estimate used to predict the likelihood of failure—was so low it suggested the tubing could have been used longer without a significant risk of failure. “They must have had a reason for doing it, but it might have been a bad reason,” he said. The qualifier “might” is required because only the company using the string can see what it looks like or know all the details about how it was used or abused.

In-Line Quench-and-Temper Technology Applied to CT Improves Safety and Reliability

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194255, “In-Line Quench-and-Temper Technology Applied to Coiled Tubing Improves Safety and Reliability in Extended-Reach US Shale Operations,” by Eric Gagen, SPE, and Gaston Piller, SPE, Coil Tubing Partners, and Irma Irais Galvan and Garry McClelland, Global Tubing, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. The paper has not been peer reviewed. In unconventional resource plays across the United States, lateral well sections are being extended beyond 10,000 ft. The increased application of larger coiled tubing (CT) of 2.375-in. and 2.625-in. diameter for operations in high-pressure wells has pushed the reliability envelope for conventional CT strings. This paper discusses the advantages of the in-line quench-and-temper (Q&T) process, which enhances overall CT life and reliability by producing tubing with more-uniform microstructure throughout its entire length, increased material strength, and improved bend-fatigue performance. Technology Background Applying Q&T technology to CT has transformed well intervention in unconventional shale plays, particularly for multistage fracturing applications in 10,000-ft laterals or longer that are commonly completed with more than 80 intervals per wellbore. With some laterals 14,000 to 16,000 ft long, with 130 or more entry points, manufacturers and service companies have strived to deliver safe, cost-effective solutions for operational challenges. The implementation of technological innovations in surface equipment, downhole tools, and Q&T custom-engineered CT strings, along with refined operational practices and logistics, allows the performance of low-risk completions with over 10,000-ft laterals on a larger scale. At the time of writing, predictions suggested that more than 90% of the US CT market would switch to Q&T products by the end of 2018. Extended-Reach CT Design With Rapid-Taper-Strip Technology Rapid-taper-strip technology, which features a quick increase or decrease of wall thicknesses within the CT string, is an engineered solution for CT applications in difficult well conditions and geometries. This technology provides rapid wall-thickness strip transitions of 300-ft to 700-ft long to place specific thicknesses purposefully along the length of the string. Rapid-taper strips combined with Q&T grades enable engineers to design unique string configurations that can achieve unprecedented well lateral reach and service life. The technology helps minimize tubing weight in the horizontal section and increase stiffness in the vertical section to avoid the onset of CT buckling inside the wells. After its successful application in North America, the flexibility and operational benefits of this strip technology became well known. It has expanded into other applications, particularly in unconventional-resource developments where CT is subjected to extremely challenging environments. With weight restrictions being the pre-dominant challenge in extended-reach CT-string designs, the flexibility of rapid-taper strips allows for custom-engineered hourglass CT strings that maximize reach, overpull, and fatigue life while meeting CT surface-equipment-design constraints. An hourglass string configuration features a reduced wall thickness in the upper end of the CT string. This reduced wall provides safe overpull capacity during operations. Hourglass CT-string configuration advantages include weight optimization, reduction of frictional pressure losses, and added rigidity where needed while minimizing wall thickness elsewhere in the string to re-duce overall tubing costs.

Coiled-Tubing Telemetry Intervention in Shut-In Conditions

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189910, “Operational Improvements Using a Coiled-Tubing-Telemetry System for a Complex Milling Operation in Shut-In Conditions,” by P. Correa, D. Parra, S. Craig, SPE, S. Livescu, SPE, A. Yeginbayev, and Z. Nadirov, Baker Hughes, a GE Company, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed. When a new horizontal well in Asia was incapable of unassisted flow, coiled tubing (CT) was selected for the perforation and stimulation intervention. Mechanical isolation was required to ensure that the stimulation fluids entered only the new zones. Accurate depth control was required for three runs: setting two composite bridge plugs (CBPs), deploying CT-conveyed perforating guns for opening two intervals, and milling out the two CBPs without taking returns to surface. For the first time, a tension, compression, and torque (TCT) subassembly was used to improve the milling operation. Introduction CT telemetry (CTT) systems have proved to be effective in enhancing operations by providing real-time monitoring of downhole data including depth, pressure, temperature, force, and torque. For data transmission from downhole sensors to surface, these telemetry systems can use either insulated wire or optical fiber. With insulated wire, power can be transferred from surface to the downhole sensors. With optical fiber, downhole batteries are required in the bottomhole assemblies (BHAs) to power the downhole sensors. When compared with braided systems using the 0.125-in. insulated electrical cable (Fig. 1), the main advantages of the CTT system are its low weight and the fact that balls can be pumped through the CT. A small wire has a minimal effect on the CT cross-sectional area. Balls up to 7/8 in. in diameter do not become stuck, and there is a minimal effect on the CT fluid pressure drop. Description of the Wire CTT System The 0.125-in.-wire CTT system has several components, such as surface hardware and software; the ⅛-in. insulated electrical conductor inside the CT string; and a BHA with different sizes, including 2.125, 2.875, and 3.5 in. The 2.875-in. BHA with three subassemblies is shown in Fig. 2. The 2.875-in. sensor assembly has the following components: Tubing end connector Head that secures the wire downhole, seals the exterior of the wire, and provides downhole electrical connection 0.875-in. ball-operated wire-release mechanism Double-flapper check-valve housing Electronic module with a casing collar locator (CCL) and pressure/temperature sensors (internal/external) Motorhead section, where a ¾-in. ball-release mechanism is located followed by a circulating port activated with 0.625-in. balls Burst-disk section enabling 0.5-in. balls to pass through to activate downhole tools

Technology Update: Biocide Treatment Program Reduces Premature Coiled Tubing Failures

Technology Update Premature coiled tubing (CT) failures have occurred in the United States, in areas such as the Eagle Ford and Haynesville formations, and the Permian Basin. In Canada, these failures once were not considered as prevalent. However, a presentation at the 2015 SPE/ICoTA conference in The Woodlands, Texas, changed that perception. A paper presented there detailed how a major Canadian CT service provider experienced a series of CT string failures while performing bridge plug millout operations in the Montney formation in northeastern British Columbia (Edillon et al., 2015). With each trip in or out of the wellbore, CT strings incur fatigue that can be estimated using simulation software based on the CT outside diameter (OD), material grade, and operating conditions. CT strings can fail for a variety of reasons, including external mechanical damage, corrosion, and excessive diametrical growth. Premature failure results not only in operational delays and the associated costs, but critical safety risks for onsite personnel. For these reasons, a study was undertaken to determine the root cause of the CT string failures in the Montney. The results showed that microbial influenced corrosion (MIC) was a contributing factor. This led the CT service provider to instigate laboratory and field studies to create a biocide treatment program. The program has successfully mitigated further CT string failures in the Montney and has now been applied to CT programs in the Eagle Ford formation. CT String Analysis Seven failures of 60.3-mm (2.375-in.) CT strings supplied by multiple manufacturers were experienced over 2½ months. The strings failed in the range of 18% to 49% fatigue—well below their predicted 80% fatigue life. Preliminary analysis of the failure points revealed pinholes and internal corrosion in the base material and at the bias weld. The filler material used in bias welds has different mechanical properties than the base pipe material, making it weaker and more fatigue-prone. To determine the failure mechanism, CT strings from four of the seven units were further analyzed by the manufacturers. In all four cases, internal corrosion pitting was observed. Comprehensive analysis on one string, including scanning electron microscopy, energy-dispersive X-ray spectroscopy, and metallography, was performed by the manufacturer and the University of Calgary. The analysis revealed that failure occurred at the bias weld and indicated microcorrosion pitting and transverse cracking in the weld filler material (Fig. 1). The corrosion morphology (rounded shape with light green corrosion debris) and the presence of sulfur in the corrosion product provided indirect evidence of MIC.

Analysis of the Critical Buckling Loads and Contact Loads on Coiled Tubing String in a Vertical Microhole

Microhole technology is a novel technology for wellbore diameters less than 88.9 mm and uses coiled tubing (CT) as the tubing string for downhole operations. The CT cannot rotate in the downhole due to the small diameter of the microhole, so that a sliding force is needed to trip the CT into the microhole. As a result, high friction is generated between the CT and the wellbore. Problems such as buckling and even lock-up occur under compressive loads, which severely impairs downhole operations of the CT in the microhole. In this work, a detailed analysis is made of CT operating conditions in a small-diameter vertical wellbore. The critical buckling loads and associated contact loads on CT strings of different diameters are calculated using well-developed models, and a study is made of the dependence of the critical buckling loads and corresponding contact loads on various parameters. The results show that the critical buckling load increases with CT diameter and that coil pitch width increases with CT diameter and a decrease in the annular clearance between the CT and the wellbore wall. The contact load between the CT and the wellbore wall increases with an increase in the axial compressive load and decreases with an increase in CT diameter. To reduce friction and contact loads and to trip the CT smoothly into vertical microholes, a larger-diameter CT and a smaller compressive load should be used while maintaining adequate annular clearance.

A New Approach to Coiled-Tubing-Integrity Monitoring

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 168303, ’Optimizing Pipe Management With a New Approach to Coiled-Tubing-Integrity Monitoring,’ by Michelle Torregrossa, SPE, Liam Zsolt, SPE, and Mirjam Zwanenburg, SPE, Schlumberger, prepared for the 2014 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 25-26 March. The paper has not been peer reviewed. With the availability of operational magnetic-flux-leakage (MFL) -measurement devices, operators are now able to see many previously undetectable coiled-tubing (CT) defects as they occur and advance. CT operators can now understand the circumstances that caused these defects, the conditions that worsen them, and the methods that can prevent their progress. This work will present an object-oriented tracking system that allows CT operators to monitor defects as they evolve over time. Introduction For many years, an integral part of pipe management has been nondestructive-evaluation (NDE) inspections of CT strings. These inspections exist to complement the use of theoretical-fatigue-life (TFL) tracking and mitigation of pipe failures. It is possible to track fatigue, imperfections, and anomalies during the job. These data should be used to optimize pipe management further in field locations. Despite its availability, the practice of conducting real-time NDE by use of MFL principles during job execution has been quite rare. Because NDE tools are becoming increasingly robust and reliable, this technology can now be used at the wellsite during CT jobs and thus data can be analyzed in real time. Sites in Alaska, for instance, run NDE devices in CT-drilling operations, and implement the findings into their pipe-management practices.

Extending North Sea Asset Operating Life With Large-Diameter Velocity Strings

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163905, ’Extending the Operating Life of Mature North Sea Assets With Big-Scale Offshore Installation of Large-Diameter Chrome-Coiled-Tubing Velocity Strings,’ by R.M. de Jonge, SPE, D. Ambergen, and U.A. Tousis, SPE, Baker Hughes, and K. Veeken, SPE, L. Hoekstra, and S. Gesterkamp, NAM, prepared for the 2013 SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, The Woodlands, Texas, 26-27 March. The paper has not been peer reviewed. In the southern North Sea, many fields Suffer from declining gas production because of reservoir-pressure depletion and associated liquid loading. At some time during the operating life of offshore production facilities, the ability for these facilities to operate economically with further decline in gas production will need to be evaluated. To avoid early abandonment of these offshore assets, well-dewatering or liquid-unloading techniques, such as velocity-string (VS) installations, are considered for extending the operating life of these mature fields. Introduction As more fields in the southern North Sea begin to mature, it becomes important to keep the wells producing economically for as long as possible. In the case of depleting gas wells, this life extension involves preventing liquid loading in the wellbore. In most gas reservoirs, the reservoir pressure will become insufficient to lift the water or condensate to the surface. As a result, the liquids accumulate in the wellbore and first will choke production then, later, will kill the well. This gas-well liquid loading occurs when the velocity of the gas up the wellbore becomes insufficient to drag the associated liquids to surface. Although many methods of liquid removal are available, only intermittent production, continuous injection of foam, and permanent installation of velocity strings are currently considered suitable for large-scale offshore application. Because many of these wells produce from small production platforms or normally unmanned installations (NUIs), a self-propelled jackup vessel was used to accommodate the coiled tubing (CT) and associated equipment. The jackup vessel has its own crane, which is large enough to lift the heavy weights, including large-diameter CT reels, onto the deck. Large-diameter (2⅜- and 2⅞-in.) chrome CT strings are being installed in deep gas wells in the southern North Sea as part of a large-scale installation project, including 20 wells over a 2-year period. The self-propelled jackup work vessel is used to house all the CT, well test, and associated equipment needed to enable well interventions on the small production platforms and NUIs. Critical to success of the project was the cross- discipline approach to preparing, selecting, and testing appropriate CT hardware and tools; performing hazard analyses; and implementing logistical coordination.

Technology Focus: Coiled Tubing Applications (June 2013)

Technology Focus In the two previous JPT coiled-tubing features, I commented on the remarkable growth the coiled-tubing industry has seen in North America, resulting largely from the shale revolution. This growth attracted numerous new players into the industry, in addition to the capacity additions made by the existing service providers. Regrettably, such unrestrained growth is rarely accompanied by a matching level of service quality. This concern about performance prompted the selection of the first paper in this feature. Although this is just one service provider’s history of stuck pipe, it likely mirrors the performance of the industry at large and serves as a reminder to all operators of the risks inherent in being too rigorous in adopting a cookie-cutter approach to certain coiled-tubing operations. The authors are to be commended for their frank reporting of the issues. In fact, the gallop toward ever-larger coiled-tubing strings has not been mirrored by increasing the size of the reels on which they are spooled. The result is that, in addition to increasing the hoop stress resulting from ever-increasing injection pressures, coiled tubing is being subjected to levels of strain that have not been encountered previously. This places strenuous demands on the bias welds in the strings and requires more-rigorous attention to string-fatigue management. This continues to be a focus of the industry, as does the slightly greater susceptibility of bias welds to pitting corrosion from recirculated formation water of varying origins. While I am still on the subject of large-diameter coiled tubing, the second paper focuses on another aspect of the industry and highlights the level of engineering detail required of many coiled-tubing activities and is especially typical of large multiwell offshore projects. It serves as an example of the level of planning and professionalism required for multidisciplinary operations but also reminds us that many superficially basic well-intervention operations are never as simple as they might appear. Finally, I could not resist a paper of a more theoretical nature because it addresses an activity of increasing importance to the industry—namely, extended reach—which, in turn, is the primary driver behind the use of larger sizes of coiled tubing. We need technology and the science behind it if we are ever going to come close to approaching the lateral reach available to the drillers. Recommended additional reading at OnePetro: www.onepetro.org. SPE 162797 New Coiled-Tubing-Deployed Multizone Stimulation Method Increases Reservoir Access by Tyson Dunlop, Halliburton, et al. SPE 163910 Coiled-Tubing-Jet-Cutting Multiple-Stage Fracture Treating Improves Fracture-Treatment Techniques To Unlock Bypassed Reserves in Cotton Valley Sands, Dorcheat Macedonia Field, Magnolia, Arkansas by R.W. Pomrenke, Bonanza Creek Energy, et al. SPE 163884 Development of a New Coiled-Tubing Life-Tracking Process by Kenneth R. Newman, KNewman Engineering

Coiled Tubing Advances Improve Extended Reach Drilling Operations

Coiled Tubing Fast setup and depth specific capabilities make coiled tubing (CT) the fastest growing technology in the oilfield services sector. Small diameter tubing spooled on a reel make for easy transportation, especially in remote areas. The main driver for CT usage stems from its ability to operate without a rig, which reduces an operator’s time and cost extensively. Because of its flexibility, the use of CT in horizontal and extended reach drilling operations has increased dramatically over the past few years. While CT can achieve efficient results at lower costs in less time, it is not a perfect solution. Small tubing size increases the chances of lockup during intervention. CT also suffers from a reduction in stiffness. In horizontal and highly deviated wells, tubing is exposed to high frictional forces as it is dragged against the wellbore and this can lead to buckling. The extended reach capabilities of CT have been extended by several methods including tractor technology and rollers, which add force at the end of the tubing, pulling it deeper into the hole. Designed in the planning phase, tapered strings can improve the efficiency of an operation, but may limit its use in subsequent intervention projects. Improved friction reduction is one of the key features to ensure against early lockup. Whether done chemically, lubricating the drillstring and the wellbore, or through buoyancy reduction, new technology is achieving results in extended reach CT applications. Horizontal Application The Bakken play in North America covers a 200,000 square mile region from Montana and North Dakota in the United States to southern Saskatchewan in Canada. Second only to Texas in oil production, the play has an estimated ultimate recovery of 24 billion bbl of oil, according to Continental Resources. The company has been active in the North Dakota Bakken since it completed the first commercially successful horizontal well, the Robert Heuer 1-17R, in March 2004. Since 2008, Continental and Sanjel have successfully performed more than 200 CT mill outs in the Bakken with more than 3,000 plugs milled. Traditionally, completion technology has drastically increased the number of fracture stages per well. Early this year, a Bakken record was set of 39 plugs in a single trip while reaching out to 10,024 ft in a lateral. Mill outs in the Bakken routinely reach more than 19,000 ft using downhole water hammer tools (WHT) and different CT string designs. As CT depths approach 20,000 ft, friction reducers are among several other technologies being sought by operators in the region.

Technology Focus: Coiled Tubing Applications (June 2012)

Technology Focus The coiled-tubing (CT) industry has experience unparalleled growth in the past year, driven directly by the massive expansion in multistage-fracturing operations in North America. Various sources estimate that the US consumed 50% of the world’s CT in the past 12 months, helping to contribute to a massive 80% growth in product coming off the CT production lines. The growth in the United States was fueled primarily by three applications: milling out composite plugs, milling out fracture-sleeve ball seats, and toe shoots (the name given to the first perforating operation before plug-and-perforate operations). Because toe shoots take place without any pressure on the well, the amount of CT life consumed by fatigue during the operation is small. Plug or seat milling, on the other hand, takes place after fracturing operations are complete and with the wellbore fully pressure charged by the formation; therefore, the CT life consumed by fatigue is high. Superimposed over the wellbore pressures are the pressures arising from circulating fluids through the CT and the milling assemblies. In some of the higher-pressure shale plays, CT strings last only for a few jobs. Accordingly, any technology that reduces the superimposed pressure could lead to longer CT life and potentially to lower completion costs. Two of the papers selected for this month’s issue involve new technologies that might be helpful to operators in this respect. However, of possible greater concern to CT companies in North America is the fact that CT use is now clearly dominated by well-completion operations, or, to put it another way, by rig count. Until recently, the CT intervention business was primarily remedial in nature and, thus, was partially cushioned from the extreme cycles experienced by drillers. However, in North America, a change has already arrived and, with gas prices at historic lows, CT service companies, CT pipe manufacturers, and CT equipment manufacturers probably need to prepare for the same swings that the rest of the well-construction industry is used to. Recommended additional reading at OnePetro: www.onepetro.org. SPE 152351 Comprehensive Approach to Production Stimulation of Massive Cold Heterogeneous Carbonate Formation Using Coiled Tubing by Vladimir Dnistryansky, Schlumberger, et al. SPE 154221 Production Logging on Coiled Tubing in a Marcellus Shale Horizontal Completion by A. McCluskey, Shell Exploration and Production SPE 154060 Best Practices for Composite Plug Milling by Steven Craig, Baker Hughes, et al. SPE 154423 Use of Coiled Tubing Deployed Expandable Technology in Sidetrack Drilling Operations by A. Caccialupi, Mohawk Energy, et al.

Spoolable Connector Allows Coiled-Tubing Operations Offshore India

Summary Available footprint on offshore platforms (Fig. 1) can be a significant challenge for coiled-tubing (CT) operations. Many times, platform limitations require that a smaller CT unit be deployed for work that would be faster and easier operationally with CT of a larger diameter. Often the platform's crane capacity dictates the size of CT used, which in turn reduces the working envelope of the CT. Some wells offshore India are completed horizontally and require intervention using larger sizes of CT in order to gain horizontal reach and manipulate sliding sleeves. When CT is used for these operations, the weight of the CT reel itself is critical to the effectiveness of the overall operation and requires proper management. Traditional methods of managing/reducing CT-reel weight involve spooling the CT string from a boat to the platform or joining CT sections by butt welding on the platform. Bringing the required length of CT onboard in two or more sections and joining them with a spoolable connector provides significant benefits over the traditional methods. The use of just one spoolable connector can reduce the maximum CT-reel lifting weight by typically 30 to 40% while increasing the CT size by one or two gauge sizes. This paper describes the results of a feasibility study performed to address typical challenges and presents actual case histories in which a spoolable connector was used to connect two CT strings. Required equipment was built and mobilized so that two separate strings could be joined on the platform with the aid of a connecting jig. Several trips were performed safely without the need to change the spoolable connector. Specific benefits of the spoolable connector over the traditional methods are explained. Methods to monitor the usable life of the spoolable connector while tripping in and out of the well (Fig. 2) will also be discussed, as well as new developments currently under way.