First Worldwide Slim Coiled Tubing Logging Tractor Deployment

Matrix acid stimulation in carbonate formations can often be vital to remove formation damage post drilling and achieve a more uniform production profile. Reaching well total depth (TD) is critical for an effective treatment in extended reach wells (ERWs) completed with an electrical submersible pump (ESP). The ESP completion with minimum restriction of 2.44-in. limits the coil tubing (CT) and downhole tools size. Hydraulically powered CT tractors are an ideal solution to pull the CT to TD (Saiood et al. 2018). The completion minimum restriction only allows for 2-in. CT with 2-1/8-in. OD hydraulically powered CT tractors and a maximum pulling force of 3,200 lbs. Pre-job CT design-aided simulations predicted the 2-in. CT size and a 2-1/8-in. CT tractor would not reach well TD due to unfavorable trajectory and therefore potentially jeopardizing a successful stimulation treatment. An alternative method is to utilize 2-7/8-in. CT combined with a 3.5-in. hydraulically powered tractor to conduct matrix acid stimulation prior to installing the upper ESP completion with restricted ID. This alternative arrangement allows for a maximum pulling force of 9,200 lbs, ensuring a greater reach in ERWs and effective treatment. It also tolerates higher pumping rates with 2.875in. CT (up to 5 bbl/min as compared with 2 bbl/min for 2-in. CT), reducing the exposure time of acid on surface, reaching optimum rates faster creating favorable wormholes in the carbonate formation and reducing the pumping operation time by up to 50%. Matrix acid stimulation is then completed with the drilling rig still in position post drilling operations. Thereafter, the upper ESP completion with restricted ID is installed. This engineered solution provides an alternative for CT interventions in extended-reach horizontal wells featuring completion restrictions, where the main challenge is to maximize the reach for optimum stimulation. The approach of combining the 3.5-in. hydraulically powered tractor with 2.875-in. CT pipe successfully enabled effective stimulation of the openhole section to a 27,000-ft. TD in a challenging downhole environment.

Artificial lift utilizing Electrical Submersible Pump (ESP) supporting operations have evolved from pump installations with no access to the completion zone to the point where rigless logging intervention operations can access the lower wellbore using either coiled tubing or wireline. Access to the completion zone has been accomplished through the installation of Y-Tool and a by-pass leg in conjunction with the ESP. The major challenge is to have the Coil Tubing (CT) plug seal assembly located on the coil otherwise a damage to the seal assembly is expected and consequently a fluid circulation might take place. CT conveyed production logging requires a CT plug to prevent production circulation across by-pass section while operating the ESP. The circulation is prevented by the seal assembly which exists in the CT plug and located on the coil tube. The Bottom Hole Assembly (BHA) consist of CT plug which included connector, sleeve and bottom crossover, all covered by the CT plug external body which has the seal assembly in addition to the Production Logging Tool (PLT). Changes in tools design and profiles allowed for a successful logging intervention into these Y-tool equipped wells while gathering required well logging data. The paper presents technical and logistic challenges during rig-less logging operations on wells with a Y-tool and a by-pass leg with complicated downhole configuration including small restriction and dual pump layouts. Examples of both impaired and successful operations will be reviewed with challenges and lessons learned, including the changes made to allow the tools for logging activities. This paper will provide a path forward to well access and surveillance while ensuring adequate isolation during logging operation.

Production logging is very essential to understand the flow profile of the formation that is being produced from. It helps to identify the contribution of the oil, water, and gas to the total fluid. To add, it is done on a usual basis to monitor the reservoir performance. Organic deposit adherence to production logging tool (PLT) spinners can hinder logging operations and result in inconclusive data acquisition. To avoid this problem, standard practices have been developed to clean out organic deposits using a standard coiled tubing (CT) reel followed by production logging using a CT reel equipped with wireline cable. Further optimization of those practices can help minimize operational cost, footprint on location, and overall job time.New CT hybrid fiber optic technology (HFOT) was deployed to meet the optimization objectives and eliminate the need for a second CT reel. The technology combines optical fibers and conductor cable with insulation to withstand corrosive fluid environments and deliver power to downhole tools, thereby overcoming prior CT system dependency on downhole batteries to run tools. The system was used in a two-run cleanout-and-logging process: first, organic deposit dissolver was pumped for wellbore conditioning purposes, before production logging was conducted with a multi-spinner production logging tool and pulse neutron tool in the second CT run.The new CT HFOT was deployed for the first time in a Middle East reservoir. Organic deposit−dissolving treatments and production logging operations were completed in four oil wells equipped with electrical submersible pumps (ESPs). After stabilizing the pressures and rates, the logging runs were conducted by recording multiple up-down passes and stationary measurements.Introduction of the new CT HFOT helped to reduce operational time by an average of 40 hours per job resulting from rig-up time optimization between CT runs, which also helped in delivering a substantial cost saving to the operator. Using one CT reel also helped in minimizing safety risks associated with personnel exposure to heavy lifting equipment during rig-up and risks associated with battery handling and management.This study illustrates job design, pretreatment preparation, operational details, and post-job result analysis. It particularly focuses on the HFOT along with a comparison with operations using a conventional CT and CT equipped with wireline cable. Readers will broaden their knowledge by learning about CT cleanout operations, logging operations, and ways in which new technology can optimize overall intervention costs while minimizing location footprint.

A number of production logs in the Troll Oil production wells have been performed. Horizontal screen sections up to 2000 m required logging tool deployment by coiled tubing. All wells flowed monophase oil. Practical correction procedures for the logs are proposed. The corrections cover annular flow between screen and open hole, coiled tubing displacement flow, coiled tubing influence on drawdown and productivity due to reduced flow area. The correction procedures are essential for interpretation of individual layer productivities, which is demonstrated on field examples. Introduction The Troll Oil field is located in 300 m water depth offshore Norway. The field is characterized by a thin oil zone (13–26 m) sandwiched between a large gas cap and active aquifers. The reservoir contains several highly permeable unconsolidated sands separated by low permeability micaceous sands. Impermeable calcite layers occur within the high permeable sands. Several publications describing the Troll Oil horizontal well development are available. The production logs performed on the Troll oil wells had two main objectives:verify cleanup of the well after setting of kill pill,determine the productivity and permeability profiles along the well. In long horizontal wells with small drawdowns (a typical value during logging at 2000 Sm3/d of the Troll Oil wells is 0.2 Bar), the production log analysis is not straightforward, and a number of corrections to the measured data must be performed to obtain representative production inflow profile along the completion interval. The most important corrections identified for the Troll Oil wells are (1) coiled tubing displacement flow, (2) coiled tubing influence on drawdown and productivity due to reduced flow area, and (3) annular flow between screen and open hole. In addition water or kill fluid accumulation at low points in the well may corrupt the spinner flowmeter response. This paper discusses possible methods to correct for these effects. A possible disturbance of the velocity profile in the screen due to radial inflow has not been accounted for. Mathematical Modeling Fig. 1 and 2 show the flow in the screen section with and without coiled tubing present. To understand the influence of the coiled tubing mass and momentum balance of a horizontal well section with and without a coiled tubing is required. The analysis is similar to that performed by Dikken, with the addition of the acceleration pressure drop and the coiled tubing effects. Mass Analysis. From Fig. 3 the following mass balance equations are obtained for a control volume with coiled tubing partly inserted (1) or, equivalently, (2) For a control volume without coiled tubing we get (3) P. 699

The lateral reach and residual bottom hole assembly (BHA) loads in extended-reach wells strongly depend on the coiled tubing (CT) mechanical friction. Detailed CT friction modeling becomes crucial in the pre-job planning stage to ensure successful job predictability. However, current numerical simulators consider constant coefficients of friction (CoFs) that are determined from similar operations without taking into account the effects of the operational and downhole parameters on the CoF for a specific operation. This study outlines the modeling of CT friction force, CoF, and axial BHA loads depending on the operational and downhole parameters when a fluid hammer tool is used. Recent theoretical, laboratory, and field data have established how CoF depends on the downhole parameters (Livescu and Watkins 2014; Livescu et al. 2014; Livescu and Craig 2015). Previously, these effects have not been considered in the CT numerical models, leading to significant CoF differences among available commercial simulators. For instance, the default CoFs in the current pre-job simulations for cased holes, when no lubricant or friction reducing tools such as fluid hammer tools and tractors are used, vary between 0.24 and 0.30 or even higher. This makes it extremely difficult to consistently evaluate and compare the friction reduction effects of lubricants, fluid hammer tools, and tractors in extended-reach wells, especially when the field operator may be consulting with several service companies utilizing different commercial force modelling software. This study presents the CT force matching and fundamental physics based on modeled fluid forces, including radial forces, drag forces, and most importantly pressure forces on the CT friction forces due to fluid hammer tools. Extending the Method of Characteristics, regularly used for studying pressure pulses in straight pipes, the Perturbations Method also accounts for the helical shape of the CT. The new CT fluid hammer model is validated against laboratory data. This rigorous method for calculating the axial BHA load and reduced CT friction force due to radial vibrations can be easily implemented in currently available tubing force analysis (TFA) software for CT operations. This novel approach, which uses detailed CT mechanical friction modeling to take into account parameters such as temperature, internal pressure, pumping rate, etc., improves predictions for CT reach in lateral wells. These findings broaden the current industry understanding of the CT mechanical friction modeling in extended-reach wells and show benefits for the industry when considering variable friction modeling in commercial CT simulators.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194284, “Pushing the Limits of Damage Identification With Coiled Tubing in Extreme Conditions: A Success Story From Japan,” by Nozomu Yoshida, SPE, Satoshi Teshima, SPE, and Ryo Yamada, INPEX, and Umut Aybar, SPE, and Pierre Ramondenc, SPE, Schlumberger, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. The paper was peer reviewed and is scheduled for publication in SPE Production & Operations. The success of water-conformance operations often depends on clear identification of the water-production mechanism. Such assessment can be complicated significantly when formation damage is also occurring. Coiled tubing (CT) and distributed temperature sensing (DTS) were combined to overcome challenging conditions (high temperature, low injectivity, high deviation, long perforated intervals, and wellbore damage) to identify damaged oil zones and suspected water-bearing zones in an onshore well in Japan. Introduction Source and location affect the selection of water-shutoff techniques, which are either mechanical or chemical in nature or a combination. No matter the operational approach, identification of the water zone is a critical step for any subsequent course of actions. One method for the identification of water-producing zones is the use of production logging. Conventional production logging uses spinners and capacitance logs to detect water flow in the wellbore. Production logging tools (PLTs) can be deployed into the wellbore using slickline, wireline, or CT. To enable real-time evaluation of the acquired data, possible options include wireline, digital slickline, and CT equipped with either a conductor cable or fiber optics. In damaged wells with high water cut, flow conditions can be unstable, with drastic changes in flow regimes. Once the well can no longer sustain stable flow because of reservoir depletion or damage in the absence of an artificial-lift method, a PLT becomes impractical. Furthermore, when wellbore conditions are complicated by the presence of debris or contaminants, data acquisition itself becomes difficult. Quantification of the damage profile and of water-producing intervals is of great importance in proper planning for subsequent operations. To address these challenges, an alternative approach was used wherein DTS obtained through fiber optics deployed with CT was used to quantify damage profiles in severely damaged wells and to identify suspected water-bearing zones by integrating complementary information. The proposed operational procedures are similar to those used for the quantification of fluid placement during acidizing operations: injection of fluid to cool down the formation and shut-in to measure rate and amplitude of temperature recovery along intervals of interest. In the present case, brine was used as the injection fluid. Quantification of the damage and injection-rate profiles are achieved by temperature inversion; the measured DTS data are matched with the simulated temperature response given by combined flow and thermal numerical models accounting for key formation and near-wellbore parameters. The subject well was suspected to be severely damaged during the completion phase and yielded a relatively high water cut during flow test. This case not only highlights the validity of the proposed approach but also details the work flow and analyses performed to obtain meaningful data and to reduce uncertainty of the interpretation. The work also raises the importance of the integration of complementary data for a comprehensive understanding of well conditions.

Maximizing reservoir contact through extended-reach and mega-reach wells has become a prevalent field development strategy for major offshore operators in the Middle East. This is especially true for the giant oilfield "A", where drilling targets go beyond 40,000 ft. measured depth (MD), with MD/TVD ratios in excess of 4.5:1. Such challenging horizons call for a detailed re-evaluation of well interventions. In 2019, the well surveillance program in the field A required intervention in a mega-reach well with a MD over 35,500 ft. and 4.5:1 MD/TVD ratio. This reach was unthinkable only a few years ago but has been made possible thanks to several recent key technological advancements, such as coiled tubing (CT) equipped with optical fiber and new CT hydraulic tractors, proactive and detailed planning during the drilling phase, the development of highly engineered CT string designs, surface equipment upgrades, and accurate software modeling. The target well is an oil producer with horizontal section beyond 23,000 ft., completed with 6 5/8-in. pre-perforated liner and 23 swellable packers placed across the 8 1/2-in. open hole section. A multiphase production logging tool was selected to assess the production profile along its horizontal drain. With a target depth beyond the reach of conventional wireline, CT equipped with optical fiber emerged as the optimum solution to facilitate reach and overcome the weight and pumping limitations of wired CT. A comprehensive CT reach modeling exercise compared the performance of several 2-in. and 2 3/8-in. CT string designs and identified operational requirements and reach gains from CT hydraulic tractors. As a result, an engineered 2-in. CT tapered string of near 36,700 ft. was developed, capable of being equipped with optical fiber line, while delivering the required flow rate and differential pressure to the CT hydraulic tractor without compromising any operational safety margin. At the time of manufacturing, this was considered the longest CT string ever produced and fitted for downhole telemetry. The operation itself set new records for well interventions in mega-reach wells, with a CT reach above 35,500 ft. MD, including a hydraulic tractoring footage over 15,650 ft. MD with spaced slugs of chemical friction reducer. This case study explains how to develop a safe, robust, and effective solution to mega-reach well challenges using the CT-conveyed optical fiber telemetry technology in one of the deepest wells in the field A, setting a new global record in CT reach. The lessons learned are now the reference for other operators in the Middle East and across the globe for performing interventions in wells that continue to be stretched in its extended reach. It also depicts why telemetry through optical fiber is key to the success of such projects and provides an overview of technology needs for the future of mega-reach well developments.

Raman to continue research on diamonds

To design accurate inflow control device (ICD) completions in high water cut wells, it is critical to have a thorough understanding of the downhole flow profile and zonal phase contribution across the zone of interest. The situation becomes more complex when dealing with an open hole horizontal section with complex trajectory, where the presence of stagnant water sumps and oil humps is common and can lead to in-accurate determination of water and oil entry zones.Production logging tools typically deployed in such environments will require to have their data quality checked, as the well conditions can either leave the spinners clogged or the holdup probes sticky with downhole debris or emulsion. Production logging tools will also need to reach the deepest point within the lateral section to ensure complete coverage of the potential flow area across the open hole section.Electrical line enabled coiled tubing (CT) technology was considered to overcome the conveyance challenges to deploy these production logging tool. The selected rugged design of the coil-to-wireline interface increased the reliability and the safety of the intervention.In this paper, a case study will be presented detailing how careful operational planning, integration between the conveyance method and the production logging tool resulted in the detailed and accurate downhole flow profile, which was then utilized in the ICD design for this well.

Young Technology Showcase As oil reserves mature around the world, oil companies look to improve the recovery of existing assets and to tap into unconventional reserves such as shale gas and tight gas. Coiled tubing (CT) and jointed tubing (JT) have progressed to larger sizes and premium material grades to adapt to these new and extended applications. However, some situations, such as long horizontal or ultradeep wells, remain where either the CT or JT is unable to provide the required reach efficiently and safely. Combining CT and JT can bring the flexibility of CT to extended-reach horizontal wells. Typical well intervention operations present several challenges, including equipment and reel availability, transportation issues, achievable flow rates, and the ability to reach the target depth of the well. CT is prone to sinusoidal buckling and eventual lockup in deviated and horizontal wells. This means that friction-reducing agents or mechanical aids such as tractors may be necessary to reach target depths. Smaller CT reduces the flow rate that can be achieved and requires higher horsepower to overcome fluid friction. JT, on the other hand, is larger and heavier than CT but requires constant making and breaking of connections during trip in and trip out, which requires redundant safety measures and reduces the effectiveness of downhole operations. In shale plays, operators have determined that laterals in excess of 10,000 ft and more than 30 fracturing stages are necessary to maximize production and achieve the desired return on investment. These wells are challenging to complete using only CT. PowerReach Service Boots & Coots, a Halliburton service, developed PowerReach, which combines CT and JT to form a hybrid string that offers the best of both. The resulting string allows for greater depth for long horizontals, high flow rates when using larger CT, and a smaller equipment footprint. The PowerReach system consists of JT at the bottom and CT on top to have the stiffness and weight of the JT at the bottom of the string and the freedom to move the CT portion on top without making connections. The length of CT depends on the length of the lateral or the distance from the first to the last section being treated. This ensures that the string can be moved freely without making a connection. Fig. 1 shows the setup of a hybrid unit on location, including a reel trailer, rig assist unit, and tower with tubing guide.

Challenging downhole environments require an unconventional integrated production logging solution that is reliable and efficient. Production logging provides information during production operations and beyond. However, conventional production logging in extended reach horizontal wells, equipped with Electric Submersible Pumps (ESPs), is complicated, as the locations of water- and oil-producing zones are uncertain due to the impurity of the borehole, caused by the presence of debris and thick material. Such downhole conditions affect the production logging tool sensors and lowers the measurements resolution. Downhole conditions can present challenges for casedhole and openhole evaluation programs, and each horizontal well presents a different complexity. The technique relies on the combination of the advanced multiphase production logging tool (AMPLT) and the pulsed neutron logging tool (PNLT). Measuring the flow rate downhole, PNLT data were acquired to complement the AMPLT spinner data when flowing at both high and low choke settings and shut-in surveys. The acquisition procedure is to allow unfavorable conditions to be logged at varying flow rates, to identify the fluid flow profile. We have studied wells equipped with ESPs to gain insight into the job planning, deployment and integration of results for horizontal well production profiling. The examples illustrate the optimization done during the job that led to successful execution. The first example is an openhole horizontal well logging case using conventional logging solution. This is followed by the second well, showing the effect of harsh environment in the openhole section on the logging tool and sensors. The last two field examples were logged recently, and the measurements and interpretation techniques are analyzed in detail in the paper. This innovative production logging solution has resulted in the successful assessment of downhole fluid entries with high confidence and safe operation despite the challenging downhole environment. Such logging is necessary to understand reservoir fluid dynamics, which is fundamental for effective reservoir management and planning more efficient workovers.

Drilling technologies are constantly being developed as operators push the envelope limits to maximize reservoir contact and increase hydrocarbon recovery. These advancements in well construction challenge the well intervention community to seek innovative solutions to successfully intervene in these wells. This paper discusses the successful combination of a slim OD measurement-while-drilling (MWD) tool run on coiled tubing (CT) for real-time survey of the open hole lateral wellbore, followed by a stimulation treatment at appropriate depths for all laterals in a single CT run.Saudi Arabia has been in the forefront of maximum reservoir contact well construction with the drilling of multilateral open hole gas wells; thus, the need for CT operations to enhance current offerings and procedures. For this application, several tests were performed to determine the feasibility of the combination of necessary tools to be able to steer, identify, and pump the stimulation treatment in a single run. MWD tools were run on CT in this multilateral gas well, and the stimulation treatment was performed during the same CT run.The common practice in the study area was to run in hole down to total depth (TD) and determine, only by depth difference, in which lateral the CT was located. The uncertainty level increased exponentially when TDs of the laterals were within hundreds of feet because the treatment could potentially be performed in an alternate lateral, rather than the one intended (Ref 1-5). With the use of MWD tools that can relay inclination, azimuth, orientation (steering capacity), pressure and gamma ray, all this uncertainty is eliminated to help ensure a positive lateral identification for proper treatment placement in the well.The MWD tool run on coiled tubing (CT), implemented a procedure explained in this paper to eliminate the uncertainty associated with previous technologies used for in real-time CT positioning inside the wellbore. The CT position is now reliable verified by survey match with real time readings from CT tip, allowing the certification of job placement in the desired wellbore path, to complete the intervention associated to the CT intervention; i.e.,: "a stimulation treatment" to be done specifically and independently for all laterals in a single run on each. This project open the doors for many other MWD-guided CT interventions to be applied in such conditions.

Well intervention challenges present opportunities to develop new technologies that increase operation efficiency and effectiveness. A revolutionary real-time hybrid coiled tubing (CT) service marks a new era of informed interventions. This paper highlights the results from 3 years of field operations using this real-time hybrid CT technology to improve well interventions economically, logistically, operationally, and technically by performing analysis and making decisions in real time. Previous techniques used wireline units to perform real-time operations, which often required production shut-in and multiple runs to avoid operational issues (i.e., tool lifting in wells with high production rates). CT electric line units mitigate the shut-in requirement, but reduce the pipe pulling capabilities and limit the fluids and rates to be pumped through the pipe. CT with fiber-optics technology helps eliminate the shut-in requirement and the fluids and rates restrictions, without affecting the CT pulling capabilities. However, operating time is limited because of the power source life. During the 3-year period, more than 1 million running feet of CT well interventions were performed in the eastern foothills of Colombia, where challenging conditions, such as high gas production rate, high tortuosity, and dogleg severity, were overcome using the real-time hybrid CT service. The real-time hybrid CT service includes an open architecture system that provides the capability to pump any fluid type at different rates through the CT and hybrid downhole tool. Additionally, the system is compatible with all electric and mechanical tools using a plug-and-play adapter to attach tools in a single rig up, which helps eliminate additional rig up and rig down of units to perform other types of well interventions. A continuous power supply allows operations to be performed without time or power constraints. This paper reviews previous case histories in which multiple interventions were successfully performed in a single run using real-time hybrid CT technology, including zonal isolation, well surveillance, access recovery, stimulations, production logging, injection logging, completion visualization, and perforating under extreme underbalanced conditions with extremely long bottomhole assemblies (BHAs). The flexibility of the real-time hybrid CT technology provides multiple opportunities to address new challenges in the oil industry without limits.

This paper presents the implementation of a semi-autonomous control system designed to optimize Coiled Tubing (CT) operations by extending CT string service life, a critical objective in reducing operational costs and improving safety. The system determines appropriate injector traction and reel tension forces based on real-time physics-based models, which are continuously updated using surface sensor inputs, calculated parameters and tubing mechanical properties. This application was field tested in the Llanos Orientales area of Meta, Colombia. The control system integrates electro-hydraulic valves with a Data Acquisition System (DAS) and programmable controller, enabling dynamic computation and application of control setpoints for the injector traction and reel hydraulic circuits. These setpoints are derived from continuously solved physics-based models that account for tubing wall thickness, axial loading, internal and external CT pressure, depth and other sensed/mechanical factors. The field trial involved mechanical cleaning of the well using a rotary tool in the production tubing with an electric submersible pump. The control system was activated while executed CT Running in Hole (RIH) and Pulling Out of Hole (POOH) during access of the 3 1/2 in tubing with 1.75 in CT from 150 ft to a target depth of 7700 ft. During RIH, the system automatically applied 800 psi to the traction mechanism and continuously adjusted the injector traction force based on real-time model outputs, including during a pull test. The system also dynamically modulated reel pressures by adjusting from 700 psi to 1200 psi in response to variations in tubing wall thickness, weight, and changes in direction from RIH to POOH. The system satisfactorily assisted the CT operator by notifying adjustments in real-time, according to CT parameters and sensor readings, without affecting the operator's autonomy to decide whether to operate in automatic or manual mode. System automation allows the application of correct traction and tension forces during CT operations by monitoring CT parameters, surface sensors, and controlling hydraulic pressures exerted by the injector and reel, taking into account the correlation of the CT region in which the axial, radial, and tangential stresses represented in the equivalent Von Mises stress equal material uniaxial resistance. This approach represents an advancement in CT automation, delivering practical value through model-driven force application, thereby extending CT life.

Use of metal-on-metal lubricants is a common way to enhance coiled tubing (CT) accessibility in extended reach (ER) wells. However, there is less data available on the effect of lubricants in open-hole applications. Historically, there is only a laboratory study (Sharma and Silviu 2020) that evaluated the effect of lubricants in an open-hole environment. This paper will discuss methodology and results from a 2-in CT field trial where a special CT metal-on-metal lubricant was utilized inside an open-hole completion to enhance accessibility to perform acid stimulation. The wells have measured depth over 17,000-ft with about 7,000-ft of 6-in open-hole lateral, requiring CT acid stimulation. The open-hole formation type is carbonate with permeability values ranging up to 10 mD. The operator requires CT to reach maximum possible depth, providing maximum coverage for acid stimulation. Proprietary CT software is used to model CT accessibility with sensitivity analysis performed with possible coefficient of frictions (CoF) expected from the laboratory research mentioned earlier. The methodology of applying the special CT lubricant is based on filling the entire well with the lubricant solution to maximize CT accessibility. These field trials were executed in October and November 2022. The plan was to run CT to the maximum possible depth in the absence of lubricant. Upon attaining friction lock, base CoF will be analyzed, and CT will be picked up to a certain depth. Special CT lubricant then will be applied at 2% concentration mixed in fresh water by pumping across the CT tubing annulus and via CT in the open-hole while running inside the hole. The special CT lubricant used in this case study was field proven to provide up 40-60% reduction in metal-on-metal CoF based on previous applications in cased completions. The open-hole effectiveness was predicted and modelled based on previous laboratory studies conducted (Sharma and Silviu 2020), which was observed to be in the range of 20 – 40% reduction in CoF for limestone samples. The actual CoF analyzed on one of the field trials was 17%. Being a first-time application of special CT lubricant in open-hole environment, the methodology and results from this field trial will enable application in open-hole wells with similar formations, globally. With more applications of metal-on-non-metal lubricants, it will provide better understanding to the industry on their behaviors downhole.