Coiled Tubing Research Articles

Digital Solutions Improve the Sustainability of Underbalanced Coiled Tubing Interventions

Summary As the global energy transition accelerates, coiled tubing (CT) operations face the challenge of delivering increasingly sustainable well interventions. This can be achieved by reducing operational time and optimizing pumping strategies without compromising operational integrity and safety. This challenge is compounded in depleted fields, where more complex interventions requiring longer operating times and facing high levels of operational uncertainty, such as underbalanced coiled tubing cleanouts (CTCOs), are increasingly needed. CTCOs in low-pressure wells rely on establishing a slight underbalance to maximize annular velocity and the carrying capacity of solids to the surface. Equivalent circulation density (ECD)—traditionally used in underbalanced drilling—and flowing reservoir pressure (FRP) are estimated in real time using a CT acquisition digital solution. The CT operation’s crew use the ECD and FRP to optimize the underbalanced environment. FRP helps define drawdown, for which there is a fine optimal operating window. An increase in ECD may incur losses, which can result in a stuck CT pipe, extend intervention time, and impact overall efficiency. A decrease in ECD may result in exceeding critical drawdown and produce unwanted solids. Real-time ECD and FRP provide the CTCO operator with the necessary information to fine-tune the pumping schedule for an efficient and sustainable CT intervention. The CT acquisition digital solution uses real-time downhole data from sensors on the CT bottomhole assembly (BHA), surface data from CT equipment, and a priori information such as the wellbore geometry to estimate critical parameters of CTCOs, including ECD and FRP. These parameters are estimated, aggregated, and plotted in real time. The underbalanced CTCO has been successfully executed in live-well conditions in gas wells with heavy inorganic scale and mixed deposits across the production tubulars, averting losses to reactivate gas production while achieving safe handling of liquid, heavy solids, and gas. Visualization of ECD and FRP enabled the underbalanced operating condition and facilitated optimizing aspects of the CTCO: CT speed, bite size, bottoms-up frequency, and frequency of solids flushing in the flowback setup. The solution and workflow optimized the cleanout interventions by eliminating nearly 24 working hours, 1,500 bbl of cleanout fluids, and 12,000 gal of liquid nitrogen as compared to the CTCO using the traditional, underbalanced approach. When compared to the traditional overbalanced approach—one that may not even be viable in highly depleted wells—the solution and workflow yield an effective reduction of 66.7% in carbon dioxide emissions (CO2e). Novel digital solutions play a fundamental role in achieving more efficient and sustainable CT interventions in underbalanced conditions by enabling on-the-fly optimizations, which reduce operational time and fluids consumed. In some cases, when downhole conditions are adverse and at the operating limit, they even make such operations possible in the first place. These underbalanced cleanouts are among the earliest implementations that leverage a CT digital solution that can be tailored to guide and enhance CTCOs amid narrow operating envelopes. The work paves the way for the development of additional execution advisors, using the same acquisition architecture, and facilitates the delivery of other CT downhole applications.

Planning Of The Coiled Tubing Gas Lift Method To Overcome Esp Start-Up Failure In Well Ppa-003

The PPA-003 well in the Puspa Structure, Jambi Field, faces technical challenges due to the start-up failure of the Electric Submersible Pump (ESP) caused by the presence of heavy complex fluids. This condition hampers the initial production process and reduces the operational efficiency of the well. This study aims to design a nitrogen (N?) injection method through coiled tubing applied alongside the ESP start-up as a solution to lift the heavy complex fluids and enable the well to flow stably. The proposed approach involves using coiled tubing to inject N? into the well during the start-up process, thereby reducing the pressure gradient inside the tubing and lowering the total dynamic head (TDH) that must be supported by the ESP pump. Once the well flows and stable flow is achieved, the coiled tubing will be removed, and the operation will continue solely with ESP support. This study includes a technical analysis of the causes of start-up failure, N? injection design, ESP performance evaluation, and well flow simulation. The research results indicate that this method is effective in overcoming start-up obstacles by reducing the density of the heavy mud (kill fluid), allowing the ESP to operate within the equipment's operational limits. The recommendations from this study are expected to serve as a reference for addressing similar challenges in other wells, particularly in the Jambi Field area.

EVALUASI ACIDIZING MENGGUNAKAN COILED TUBING UNIT UNTUK MENGHILANGKAN SCALE PADA SUMUR RPN-3 LAPANGAN PAD-A

Over time, Well RPN-3 has experienced a decline in production. Acid stimulation is one of the efforts to enhance the productivity of wells facing decreased production due to scale deposits in the perforation zone, tubing, flowline, or surface equipment. Scale is a deposit formed through the crystallization and deposition of minerals contained in formation water. To address scale-related issues and potentially increase production, acid stimulation is employed. The acid stimulation on Well RPN-3 is carried out using the coiled tubing unit method. Coiled tubing technology is chosen for its ease of mobilization and its ability to deliver acid directly to the target interval. Well RPN-3 is selected due to its significant decline in production. Laboratory analysis of scale samples taken from Well RPN-3 revealed the presence of calcite-type scale (CaCO3), suggesting that the production decline is likely attributed to the presence of this scale. Indicators of the success of acid stimulation operations can be observed through the increase in production rate (Q), the Inflow Performance Relationship (IPR) curve, and the Productivity Index (PI).

Technology Focus: Coiled Tubing (June 2025)

_ As I write the introduction to this year’s Coiled Tubing feature, I would like to mention that this year saw the 30th anniversary of the SPE/Intervention and Coiled Tubing Association (ICoTA) Well Intervention Conference and Exhibition in Europe, which proved to be an outstanding event, as usual. The Curtis Blount Outstanding Paper Award was won by TechnipFMC (in collaboration with Halliburton) for “Riserless Coiled Tubing Services From Light Well-Intervention Vessel: First Operation in a Live Subsea Well.” Other excellent finalists included entries from E Plug (TorcCollector), Baker Hughes (PRIME Compact Puncher), Welltec (Wellgrab), and SLB (High-Resolution Dual-Caliper and Slim Multielement Cement and Corrosion Tool Combination). This year, ICoTA added a further sign of appreciation for the award winner—fully funded travel to a chosen ICoTA conference worldwide. I encourage readers to investigate these technologies. Furthermore, in other notable ICoTA developments, ICoTA Asia was officially established as an organization this year; its first conference is scheduled for 2–3 December 2025 in Kuala Lumpur. ICoTA also announced the re-establishment of its China chapter. The ICoTA Europe chapter, based in Aberdeen, is hosting several events for young professionals, ideal for networking and meeting experts to gain insights into the industry, so make sure to book your free tickets and participate. As for this year’s selected papers for the Coiled Tubing feature, one includes a discussion of a first-time technology breakthrough of CO2-injection pumping using coiled tubing for Project Greensand in Denmark, a consortium of Danish government and several oil and gas operators aligned to test achieving carbon capture in depleted oil well reservoirs. With storage operations set to get underway at the end of 2025 or early 2026, Project Greensand is expected to become the first CO2 storage project in the EU intended to mitigate climate change. The second selected paper is a health, safety, and environment (HSE) -oriented study that explores coiled tubing intervention with a novel approach to safely remove scale containing naturally occurring radioactive materials offshore Abu Dhabi. The third paper, the winner of the Curtis Blount Outstanding Paper Award, demonstrates the future of subsea well intervention through vessel-based coiled tubing operations offshore Europe. Each of these papers presented at SPE conferences exemplifies engineering solutions to maximize commercial value while retaining focus on HSE and service quality. Summarized Papers in This June 2025 Issue SPE 224032 - Riserless Coiled Tubing Services in Live Subsea Well Enhance Efficiency, Safety by Per Buset, TechnipFMC, et al. SPE 222569 - Pilot Project for Carbon Dioxide Injection Uses Coiled Tubing and a Retrievable Bridge Plug by Ksenia Starodubtseva, SLB, et al. SPE 220493 - Novel Approach Removes Scale Contaminated With Naturally Occurring Radioactive Material by Kamil F. Salahat, ADNOC, et al. Recommended Additional Reading at OnePetro: www.onepetro.org SPE 221847 - Breaking New Ground in Reservoir Management: Kuwait’s First Underbalanced Coiled Tubing Drilling Operation for Blowout Relief in West Kuwait—A Global Success Story by Sebastian Sierra Martinez, SLB, et al. OTC 35468 - Step Change in Coiled Tubing Drilling Strategy of Multilateral Drilling Using Underbalanced Coiled Tubing Drilling Technique in an Onshore Sour Gas Field, UAE—Case Study by Mohamed Osama, Abu Dhabi National Oil Company, et al. SPE 220603 - Coiled Tubing Downlines Corrosion and Preservation Experience From Extended Riserless Light Well-Intervention Campaigns by R. Mammadli, BP, et al.

Riserless Coiled Tubing Services in Live Subsea Well Enhance Efficiency, Safety

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 224032, “Riserless Coiled Tubing Services From Light Well Intervention Vessel: First Operation in a Live Subsea Well,” by Per Buset, SPE, Bernt Gramstad, and Mark Howitt, TechnipFMC, et al. The paper has not been peer reviewed. _ Riserless light well intervention (RLWI) offers several advantages over riser-based intervention. Traditionally, only wireline and slickline services could be performed in riserless mode. Thus, if coiled tubing (CT) were required, typically it was necessary to switch to a riser-based intervention. The introduction of riserless coiled tubing (RLCT) addresses this issue, enhancing capabilities for a wide range of operations. This paper describes the first RLCT operation performed in a live subsea well. RLCT Technology Overview The RLCT capability has been developed as an add-on service to existing RLWI capabilities. The complete paper provides examples of its successful deployment in various applications. The system uses the standard RLWI stack. The pressure control head used for normal cable operations is replaced by a subsea stripper and subsea injector. The subsea stripper includes three CT sealing elements like the ones used for surface applications. The sealing elements provide redundancy and help ensure effective sealing around the CT. The sealing elements can be replaced at surface in between runs because the stripper and injector are retrieved to surface when changing the bottomhole assembly (BHA), but they cannot be changed subsea in the middle of a run. The main function of the subsea injector is to inject the CT into the well, overcoming the stripper friction and the extrusion force caused by the borehole pressure acting on the CT cross section. The subsea injector operates in combination with the surface injector to maintain the CT in tension between surface and seabed. At surface, a standard CT injector mounted on a heave-compensated platform runs on the rails of the tower cursor system. The CT injector and cursor system hang in the tower active heave-compensation winch together with a passive heave compensator. The rest of the CT spread is standard and can be configured according to specific project requirements. Preparation In 2021, it was decided to develop the RLCT system further for use in live wells, integrating a subsea injector and subsea stripper onto the existing RLWI stack. Several oil companies joined forces to progress qualification and system development. A subsea stripper was designed, built, tested, and qualified. In 2023 and 2024, the same design, testing, and qualification process was performed for a lighter version of the subsea injector used in previous projects. Extended system testing was performed in 2024, including training and familiarization of offshore personnel. A surface test facility was built for system testing, control-software development and debugging, and hands-on training of personnel. In June 2024, a wet test of the stripper and injector was performed. The associated procedures and remotely operated vehicle interfaces and operations also were tested before performing a full test program on a test well. The well identified for the first operation of the new RLCT system was in the central North Sea, equipped with a 4-in.×2-in. vertical tree in a water depth of 130 m. The well had been shut in for many years and had been temporarily suspended with the installation of a temperature-activated suspension plug. To gain access to the well, a parted safety valve would have to be fished with 7/32-in.braided line.

Pilot Project for Carbon Dioxide Injection Uses Coiled Tubing and a Retrievable Bridge Plug

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 222569, “Pilot Project for CO2 Injection Using Coiled Tubing and a Retrievable Bridge Plug,” by Ksenia Starodubtseva, Azwan Hadi Keong, SPE, and Andrei Casali, SLB, et al. The paper has not been peer reviewed. _ Project Greensand is Denmark’s leading CO2 sequestration project, expected to store between 4 million and 8 million metric tons of CO2 per year by 2030. An offshore CO2 injection trial in a depleted and inactive reservoir was conducted recently to evaluate the injection of CO2 into an existing water-injection well in the Danish North Sea. This operation demonstrated the possibility of using conventional intervention equipment and services as part of an early-phase enabler for a carbon-storage project. Introduction To meet climate objectives, Denmark acknowledges CO2 storage as a central solution. The vision for this effort is being realized through Project Greensand, backed by the Danish government. Project maturation entails a pilot test period with live CO2 injection, wherein CO2 is provided in batches by a marine vessel. In March 2023, the second phase of the Greensand project was executed successfully. This involved the transportation of CO2 in International Standards Organization (ISO) storage tanks on a vessel from Antwerp, Belgium, to the Nini platform in the North Sea. Coiled tubing (CT) was used to deliver liquid CO2 into the formation while safeguarding an active water-injection well from exposure. In total, approximately 4,100 metric tons of CO2 were injected effectively to a depth of 1800 m below the seabed. The Nini field featured promising geological conditions, combined with the availability of reservoir data gathered over more than 2 decades. During the pilot phase, the CT string remained in the well for a period of up to 90 days, during which seven cycles of CO2 were transported in batches of nominally 800 tons each from a capturing facility in Antwerp to the platform, injecting it into the perforations using CT deployed in the selected well. CO2-Handling Risks and Hazards CO2 hazards related to the release are different than those encountered with conventional oil and gas. These hazards include the following: - CO2 may cause asphyxia - Very low temperatures are used for handling and release - Released gas will be much heavier than air - CO2 can form hydrates when water-wet - CO2 is corrosive if free water is present To mitigate the risk of a sudden release of CO2, several measures were implemented. First, equipment operators were required to wear appropriate personal protective equipment to protect them from low temperatures during venting and draining. Second, the compatibility of all surface and downhole equipment, particularly sealings, with CO2 was assessed and monitored carefully. Third, all surface and well-control equipment underwent pressure testing before commencement of CO2 pumping. Finally, any CO2 venting was directed to a designated bleed point outside the working zone to minimize potential risks.

Novel Approach Removes Scale Contaminated With Naturally Occurring Radioactive Material

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 220493, “Novel Approach for NORM Scale Removal,” by Kamil F. Salahat, SPE, Gladwin Correia, SPE, and Sarah Al-Tamimi, ADNOC, et al. The paper has not been peer reviewed. _ Upper Zakum is one of the largest offshore oil fields in the world, approximately 80 km offshore Abu Dhabi. One of its developmental challenges is its shallow depth of 5–15 m, which makes conventional drilling and production platforms impractical and costly. The operator has created four artificial islands to serve as bases for drilling and production facilities. The islands are designed to minimize environmental impact, maximize oil recovery, and reduce operational costs. Overview of Radioactive Scales in Oil and Gas Generation and Nature of Naturally Occurring Radioactive Material (NORM). The cause of the formation of NORM as scale adhering to equipment and tubulars is water-soluble radiochemical compounds that occur naturally in the geological formation of the hydrocarbon reservoir and are transferred through the system together with the produced water, where they form commonly less-soluble compounds and precipitate as a mineral scale under certain chemical, mechanical, and thermodynamic conditions. The primary radioisotopes of concern in oil and gas industry NORM, forming the metal part of this scale, are related to the uranium/radium decay series and the thorium/radium decay series but also to potassium-40; these occur freely in the Earth’s crust. Not frequently reflected in the evaluation of NORM is the actinium decay series. Health, Safety, and Environment (HSE) Concerns Related to NORM. For these unstable, naturally occurring radionuclides, also referred to as radioisotopes (uranium, thorium, radium, and radon) to become more stable, the nuclei eject or emit subatomic particles and high-energy photons (gamma rays). Exposure to this ionizing radiation from the existing isotopes in NORM may cause detrimental effects to the human body and, in the long term, may lead to adverse health effects including cancer and leukemia. The regulations of the Federal Authority of Nuclear Regulation—the national regulator in the United Arab Emirates—and the steps taken to meet their compliance are detailed in the complete paper. Candidate-Wells Selection Various wells were selected as possible candidates for rigless intervention with coiled tubing (CT). The two wells selected for NORM scale cleanout with CT had already seen intervention in the past without satisfactory results. Well A was drilled and completed in 2015, without indications of scale buildup for several years. During later various diagnostic attempts with wireline, however, obstructions were encountered, with scale deposits accumulated on the toolstrings. A remedial intervention was performed in 2021, including a preliminary bullheaded acid treatment, followed by mechanical scale removal with a hydraulic motor and mill deployed with CT. During the operation, the milling progress was extremely slow and complicated because of frequent plugging of the rock catcher. Soaking of additional acid pills and scale dissolvers allowed better progress in terms of depth, but the dislodged scale continued plugging the return system.

Autonomous Flow-Control Devices Optimize Matrix Acid Stimulation

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 221914, “The Feasibility of Autonomous Flow-Control Devices for Matrix Acid-Stimulation Operations in Carbonate Reservoirs,” by Virochan Ganjoo and Mojtaba Moradi, SPE, TAQA. The paper has not been peer reviewed. _ The challenge of matrix acidization remains the fair distribution of the acid treatment along the wellbore. Acid prefers the less-resistant spots along the wellbore characterized by high-permeability streaks or fractures. To counter this challenge, a completion consisting of autonomous outflow-control devices (AOCD) was implemented. In the complete paper, a novel approach is developed through modeling to demonstrate that autonomous flow-control devices can provide substantial value in stimulation operations. AOCD Technology This paper is specific to the use of AOCD in acid-stimulation operations, presenting it as an option for injection wells irrespective of the planned operation. This option also adds value because acids can be bullheaded from the surface, eliminating the need for expensive and complex coiled tubing service. The device works as a binary product. First, when the flowing conditions are below the critical values of rate or pressure drop, it works as a flow-control device (FCD) open to flow. Second, once the critical rate or pressure parameters are met, the device shuts off, restricting flow to that zone. The device moves back to the open position once the pressure drop across it is eased. At the heart of the device is a spring system that keeps it open until enough force is exerted by the flowing fluid to compress the spring and close the device. This design allows the closure trigger point to be adjusted by changing the nozzle size and spring constant. Reopening can be achieved by stopping the pumping operation at the surface and deploying passive FCDs in the same completion zone as the AOCD to balance the pressure. Prejob modeling will provide an overview of how the pumping operation will proceed, but the AOCD also will account for dynamic changes during the operation. Smart completion design is based on partitioning a wellbore into multiple zones using packers. Single or multiple autonomous FCDs can be placed in each zone. These devices, located on the base pipe along the wellbore, are open during deployment and enable acid or water injection at the usual distributed rates. As the rates increase, the zones characterized by higher permeability will reach the trigger point faster than other zones. Thus, the injection in these zones will be highly restricted, which will divert the flow to lower-permeability zones. The target operational rates and pressures can be managed based on application through prejob modeling. The case used for modeling the comparative study focuses on a heterogeneous reservoir with fractures. As injection begins, the pressure buildup in the reservoir will decrease because of the effect of inducing a fracture or propagating it; thus, the injection in this zone will increase exponentially. This will create a higher pressure drop across the device, which will push the main nozzle and spring toward the seal face, consequently shutting the injection path, as shown in Fig. 1, where the cross section of the device is shown in open and closed positions. Therefore, the outflow into this zone is taken over by FCDs, thus reducing the injection rate significantly. The device is fully reversible once the conditions are met.

Study on helical post-buckling of motional coiled tubing in horizontal wells

Coiled tubing is widely used in oil and gas operations. However, the long coiled tubing may undergo sinusoidal or helical buckling deformations, and even lock-up, leading to property damage and serious accidents. To study boundary conditions effects on helical post-buckling of coiled tubing in horizontal wellbores, firstly, the mathematical model containing dynamic terms for nonlinear buckling deformation of coiled tubing in horizontal wells is established in this paper. Secondly, using the improved perturbation method, the third-order perturbation solution of the relationship between pitch and time during helical post-buckling of coiled tubing in horizontal wells is obtained, and the expression of the contact force between coiled tubing and wellbore wall with the time terms is derived. Finally, the effects of gravity, the change velocity of the pitch, and the axial load on the contact force are analyzed separately. The results show that when considering the effect of gravity, the axial internal stress in each micro-element segment of coiled tubing undergoing helical post-buckling exhibits periodic variation. The greater the compression velocity, the greater the contact force between coiled tubing and the wellbore wall. The discriminative conditions for the occurrence of lock-up in coiled tubing undergoing helical post-buckling are proposed, and increasing the axial load can delay the occurrence of lock-up. The mathematical model established in this paper innovatively incorporates time-dependent dynamics, and breaking through the limitations of the traditional quasi-static assumptions of buckling analysis. This model provides a new method and theoretical basis for further study of coiled tubing helical post-buckling process.

Digital twin and contact analysis of ultra-long distance coiled tubing operation structures

Background Coiled tubing operation is a high-quality operation method that considers both cost and efficiency in current oil and gas well operations. There is a significant difference between the calculation and prediction before operation and the actual operation. The reason is that the complex wellbore trajectory makes it difficult to evaluate the contact state between coiled tubing and wellbore, resulting in a significant error in the pipe string mechanics calculation and analysis. Methods In this study, a digital twin-based method for continuous tubing wear modelling is proposed. Firstly, the digital twin unit of continuous tubing-wellbore is constructed to achieve the fusion modelling of three types of information, namely structure, physical field and material, of the micro-element well section. On this basis, a feedback-corrected contact algorithm is introduced to dynamically identify and correct the contact state of continuous tubing under different downhole running trajectories. By constructing a spatial and temporal two-dimensional digital twin of the continuous tubing operation process, the accurate positioning and historical state tracing of the tubing entity in the complex downhole environment are realised. Results The research results show that the digital twin coiled tubing and contact algorithm can effectively predict the contact state of coiled tubing operations; the verification model shows that the contact algorithm can accurately analyze the contact state of different well trajectories. Conclusions The digital twin of the coiled tubing operation structure and its contact algorithm can effectively solve the problem of deterministic friction state in the process of mechanical calculation of the tubing string, which has important guiding significance and engineering value for the mechanical calculation and operation safety analysis of coiled tubing operation.

Modeling the Temperature and Pressure Variations of Supercritical Carbon Dioxide in Coiled Tubing

The use of supercritical carbon dioxide (SC-CO2) coiled tubing drilling technology for developing heavy oil and other special reservoirs offers significant advantages, including non-pollution of oil layers, prevention of clay swelling, avoidance of reservoir damage, compact footprint, and enhanced oil recovery, making it a highly promising innovative drilling technology. The thermo-hydraulic coupling characteristics of SC-CO2 in helical coiled tubes are critical to the design of SC-CO2 coiled tubing drilling systems. However, existing models often neglect thermal conduction, variable thermophysical properties, and friction-compression coupling effects, leading to significant deviations in the prediction of temperature and pressure variations. Considering heat transmission and fluid dynamics, a coiled tube heat-transfer model which considers varying properties of both pressure and temperature has been developed based on an optimized convective heat-transfer coefficient. Then, the physical parameters of the carbon dioxide in the helical coiled tubing were researched. Results indicated that the temperature change of carbon dioxide in helical coiled tubing was small due to the low temperature difference between the carbon dioxide and the air as well as the existence of an air interlayer and low natural convective heat-transfer efficiency. The drop in pressure of the carbon dioxide increased with increasing coiled tubing length, and the pressure was half that of the conventional drilling fluid in the same condition due to its low viscosity. The density of carbon dioxide in the helical coiled tubing changed from 1078 kg/m3 to 1047 kg/m3 with increasing coiled tubing length under the conditions stated herein, and the carbon dioxide remained liquid throughout the whole process.

Analysis of Coiled Tubing Sidetracking Technology

Coiled Tubing Drilling (CTD) technology has significant technical advantages over traditional rotary drilling technology and has been widely applied in international oil and gas exploration and development. Its application scenarios include shallow vertical well drilling, re-entry sidetracking, reservoir deepening drilling, underbalanced drilling, and offshore platform drilling. Through continuous technological breakthroughs in recent years, China has made significant progress in the development of coiled tubing sidetracking equipment, supporting tools, and process optimization. The field testing and engineering application of small-hole coiled tubing sidetracking technology have been successfully achieved. This paper systematically reviews the current status of small-hole coiled tubing sidetracking equipment and technological development both domestically and internationally. Through the analysis of typical well cases, the field application effects of small-hole coiled tubing sidetracking technology are explored in depth. Based on the development needs of China's oil and gas fields, future development directions and key research areas for small-hole coiled tubing sidetracking technology are proposed.

Feasibility analysis of coiled tubing running into long horizontal wells of shale gas

With the rapid development of shale gas, the demand for long horizontal wells has significantly increased, to improve the accuracy and safety of coiled tubing operations in drilling, this study establishes a mechanical analysis model for coiled tubing drilling into shale gas long horizontal wells based on friction coefficient, considering factors such as wellbore trajectory, operating conditions, and pipe structure. This study considers the buckling effect and investigates the feasibility and buckling behavior of coiled tubing in horizontal wells. Guidelines for determining coiled tubing accessibility have been developed. The fourth-order Runge-Kutta method was used to solve the established model and analyze the factors affecting the feasibility of coiled tubing operation. The calculation results are highly consistent with the on-site data. The research results indicate that the mechanical properties and states of coiled tubing vary depending on the wellbore trajectory and drilling fluid type, and the final depth of penetration also varies. Large size coiled tubing is beneficial for improving its mechanical properties and increasing its extension distance. This study can serve as a reference for optimizing the construction parameters of underground coiled tubing operations.

Multiscale Synergistic Strengthening-Toughening Mechanisms in Lanthanum Oxide-Modified Coiled Tubing Welding Wire Deposited Metal

With the increasingly demanding service conditions of coiled tubing, its welded joints require superior synergistic strength-toughness properties to meet comprehensive mechanical performance requirements. This study achieved synergistic optimization of strength and toughness in deposited metal via lanthanum microalloying technology and elucidated microstructural evolution mechanisms and fracture failure mechanisms via multi-scale characterization techniques. The results demonstrate that lanthanum oxide addition effectively modifies inclusion characteristics, inducing phase transformation from O-Mn-Si-Al-Ti to O-Mn-Si-Al-Ti-S-La, with average particle size significantly decreased from 0.19 μm to 0.12 μm. The deposited metal microstructure comprises lath bainite and granular bainite. The addition of 0.5 wt.% lanthanum oxide results in significant microstructural refinement: average grain size decreases from 1.16 ± 1.18 μm to 1.02 ± 1.00 μm, while granular bainite volume fraction decreases from 8.6% to 4.7%. The microstructural optimization also enhances mechanical properties substantially: yield strength increases from 628 ± 14 MPa to 673 ± 12 MPa, and impact toughness improves from 160 ± 6 J to 189 ± 6 J. Mechanistic analysis revealed that proper addition of lanthanum (0.5 wt.%) promotes grain refinement via heterogeneous nucleation and modifies inclusion morphology, effectively inhibiting crack initiation. However, excessive addition (1.0 wt.%) induces inclusion clustering, forming stress concentration sites that degrade mechanical properties.

Enhancing The Productivity of an Eruptive Petroleum Well by Reduction of Water Inflows

The issue of water inflows is one of the major concerns in the oil industry. This paper presents studies conducted in 2020 on the X field's well M.01, which, over the years, encountered challenges related to water inflows, though its initial production had no such issues. The primary objective of this paper is to propose a viable solution to reduce water inflows, thereby maximizing surface oil production in a cost-effective manner. To achieve this, a nodal analysis was conducted to evaluate the well's performance in terms of liquid flow (water and oil). Production logs were used to identify the new oil saturation zone, where new perforations were made. Finally, an economic assessment was performed using the production decline prediction curve. Confidential data, including completion, reservoir, log, and economic data, were processed using PIPESIM and EXCEL software. According to the results, water inflows in well M.01 were caused by the displacement of the water-oil contact, due to partial penetrations via the water cone phenomenon, which reduced oil flow from 3005.585 STB/d to 241.9834 STB/d. To address this issue, a perforation was made using coiled tubing at the 100% oil saturation zone, and the two levels were isolated using a plug via a slickline. This intervention resulted in an oil flow of 2931.087 STB/d, with a water flow of 325.6764 STB/d. After production optimization using wellhead pressure sensitivity curves and flowline diameter adjustments, oil flow increased to 3872.435 STB/d, and water inflow decreased by 90%. The critical flow rate calculation indicated that production must not exceed 5150 STB/d to avoid a rapid water breakthrough. The project to perforate only in the oil saturation zone for optimal production is projected to remain profitable for 11 years, with a return on investment in 1 year, 7 months, and 8 days.

Innovative Approach Integrating Machine Learning Models for Coiled Tubing Fatigue Modeling

Coiled tubing (CT) plays a pivotal role in oil and gas well intervention operations due to its advantages, such as flexibility, fast mobilization, safety, low cost, and its wide range of applications, including well intervention, cleaning, stimulation, fluid displacement, cementing, and drilling. However, CT is subject to fatigue and mechanical damage caused by repeated bending cycles, internal pressure, and environmental factors, which can lead to premature failure, high operational costs, and production downtime. With the development of CT properties and modes of application, traditional fatigue life prediction methods based on analytical models integrated in the tracking process showed, in some cases, an underestimate or overestimate of the actual fatigue life of CT, particularly when complex factors like welding type, corrosive environment, and high-pressure variation are involved. This study addresses this limitation by introducing a comprehensive machine learning-based approach to improve the accuracy of CT fatigue life prediction, using a dataset derived from both lab-scale and full-scale fatigue tests. We incorporated the impact of different parameters such as CT grades, wall thickness, CT diameter, internal pressure, and welding types. By using advanced machine learning techniques such as artificial neural networks (ANNs) and Gradient Boosting Regressor, we obtained a more precise estimation of the number of cycles to failure than traditional models. The results from our machine learning analysis demonstrated that CatBoost and XGBoost are the most suitable models for fatigue life prediction. These models exhibited high predictive accuracy, with R2 values exceeding 0.94 on the test set, alongside relatively low error metrics (MSE, MAE and MAPE), indicating strong generalization capability. The results of this study show the importance of the integration of machine learning for CT fatigue life analysis and demonstrate its capacity to enhance prediction accuracy and reduce uncertainty. A detailed machine learning model is presented, emphasizing the capability to handle complex data and improve prediction under diverse operational conditions. This study contributes to more reliable CT management and safer, more cost-efficient well intervention operations.

Cemented Multientry Fracturing System Proves Effective for Deep Tight Gas Wells

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23680, “15,000-psi Multientry Cemented Multistage Fracturing System: Alternative Completion Method for Deep Tight Gas Wells,” by Rasim Serdar Rodoplu, SPE, and Awad Alenezi, SPE, Saudi Aramco, and Mohammed Dahlan, NOV, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ A cementable multientry (ME) multistage fracturing (MSF) completion technology with a true 15,000-psi pressure rating was developed for use in deep tight gas wells. The completion system brings operational and design improvements to MSF methods typically used in these types of wells. The complete paper provides details on the development of the novel system, considering the harsh well conditions, its ME design used for creating multiple fractures across each stage, and its advantages over traditional openhole (OH) MSF solutions. Cemented ME-MSF Completion System Overview A conventional OH-MSF completion system includes OH packers, OH anchors, hydraulic fracturing ports, and ball-actuated fracturing ports. The cemented ME-MSF completion system is similar, but no packer or anchor is required because zonal isolation is provided by the cement. Fracturing sleeves are activated by dropping a ball. Multiple stages can be configured in the wellbore; each stage might contain several sliding sleeves for fracture initiation in the ME configuration. More flex seats can be placed per stage. The system is installed as an integrated part of the lower completion string and can be used in horizontal or vertical wells. Once the completion reaches the total depth (TD) of the well, it is cemented in place and a wiper dart is pumped from the surface. The main purpose of the wiper dart is to ensure that the inside of the tubulars, fracturing sleeves, and ball seats are wiped free of cement to achieve a fully cemented MSF completion. The first stage of the cemented ME-MSF completion system is an exception in terms of a fracturing sleeve through a hydraulic port that is opened by pressuring up the completion. For the remaining stages, a fracturing ball is dropped and pumped from surface to operate the multiple sleeves in the corresponding stage so that the stimulation treatment can be carried out in a continuous pumping operation. Flexible cemented ME sleeves are installed. These expanding seats allow a single ball per stage to operate multiple sleeves before isolating the stage with a fixed seat. This allows the fracture treatment to be distributed throughout the stage instead of exiting at a single point. Thus, the stimulation treatments result in more-efficient distribution along that specific compartment of the well. This configuration allows continuous rigless pumping operations with no need for perforation or plug setting between stages. Compared with plug-and-perforation (P&P) operations in cemented liners, the presented completion system eliminates wireline and coiled tubing (CT) or milling operations. In addition, it reduces completion time, cost, and water consumption. For effective stimulation, stage isolation must be maintained by cement so that no communication exists between the stages because no OH packer is involved in this system. The cemented ME-MSF completion system is composed of fewer items compared with OH-MSF systems that may use OH packers and OH anchors.

Study on the optimal structure of nonmetallic coiled tubing with cable-laying based on the minimum stress in optical fibers

Study on the optimal structure of nonmetallic coiled tubing with cable-laying based on the minimum stress in optical fibers

Research on the Mechanism and Prevention Countermeasures of Stuck Coiled Tubing During Coiled Tubing Fracturing in the Junggar Basin

The coiled tubing (CT) fracturing technology offers advantages such as pressurized dragging operation and maintaining a large borehole diameter after fracturing. However, during fracturing in the conglomerate and volcanic rock reservoirs of the Junggar Basin, CT stuck during retrieval occurs frequently. In this study, a model simulating the variation in the in situ stress field during CT hydraulic fracturing is established based on elastic mechanics and the displacement discontinuity method (DDM). Based on the geological characteristics of conglomerate and volcanic rock reservoirs in the Junggar Basin, and considering engineering parameters such as fracture length and fracture count in CT hydraulic fracturing, this study investigates the variation in the in situ stress during CT hydraulic fracturing and explores the stuck mechanism of CT. An index for fracturing completion is constructed to evaluate the stuck of CT during the fracturing process. With the goal of full stimulation of the horizontal section, a quantitative optimization design is conducted for the fracturing stage spacing and number of stages under different geological conditions, resulting in corresponding charts. The results indicate that the stuck mechanism during CT fracturing is caused by the continuous accumulation of stress induced by hydraulic fractures, leading to stress inversion. The fracturing completion increases with the stage spacing and the original horizontal stress difference. The length of the fractured section first increases and then decreases with the increase in stage spacing, while it increases with the original horizontal stress difference. The research findings can be applied to the optimization design of stage spacing and number of stages for CT hydraulic fracturing in conglomerate and volcanic rock reservoirs of the Junggar Basin, effectively preventing and controlling stuck coiled tubing in CT fracturing.

Analysis of the Fracture Failure of ST90 Coiled Tubing

This article determines the causes of fracture failure of the ST90 coiled tubing through chemical composition analysis, dimensional measurement, metallographic analysis, and hardness testing of the fractured tubing sample. The material test results show that the chemical composition, size, grain size and hardness test results of the fractured coiled tubing meet the standard requirements, and no abnormal results are found. There is mechanical trauma in the fracture and suspected improper operation on both sides of the fracture position, which causes the tube body damage by the stacking of the clamping blocks, that will cause the deformation of the coiled tubing. The thinning of the wall thickness and the increase of hardness will reduce the strength of the tubing, which is the main reason for the fracture of the coiled tubing.