The requirement of tapping new hydrocarbon reserves has pushed the Middle East region to develop its unconventional resources. During the development, longer laterals are drilled to achieve more stages and increase well productivity. This generates more complex intervention activities, including the post-fracturing plug millout with coiled tubing (CT). This study outlines comprehensive evaluation of frac plug milling practices integrated with designing and execution of CT operations to improve overall milling efficiency for these unconventional horizontal wells. Milling optimization was obtained by tackling key enablers of higher efficiency. First, the CT string was precisely engineered to serve the well trajectory and completion size. The tapered wall thickness configuration was strategically planned to maximize stiffness at the highly deviated section while reducing weight on the long horizontal lateral. Plug selection and placement strategy were also meticulously planned to configure the best combination of composite and dissolvable plugs. Since different plug types behave differently during milling, the millout strategy was tailored specifically for each type and their actual downhole environment. The new engineered CT design, coupled with an extended reach tool (ERT), was proven effective in overcoming reach challenges across the long lateral while maintaining sufficient weight-on-bit (WOB) to mill the plugs. The ERT was also observed to enhance milling action due to the vibrations it generated. Those improvements led to faster and smoother operations, resulting in 70% reduction of operating time compared to the baseline established prior to the start of the project. The comprehensive plug placement strategy and better understanding of different plugs behavior in different environments further improved the milling efficiency, as the average milling time per plug was reduced by 80%. Additionally, the reduction in operating time improved the environmental sustainability of the project, as carbon emissions from the CT unit were reduced. The comprehensive engineering design and plug selection strategy delivers significant improvements in millout efficiency. Implementation of key enablers led to performance increase, better resource utilization, and further cost optimization. This achievement also aligns with initiatives to reduce the impact of oil and gas operations on the environment, thus contributing to the goal of achieving net-zero in carbon emission.

While the industry has many recommendations on fishing operations and setups, a process of the selection for overshots, and a streamline when similar fish or wellbore conditions has not been discussed before. This paper will review a challenging case history well, with multiple fishes of the same type, and the lessons learned on selections with varying wellbore conditions. Taking into measure was the learnings from the post well review, and the creation of a flowchart to better optimize the selection of fishing Bottom Hole Assembly's (BHA). This incorporated the coordination of charts’ creation with the service provider, ensured a robust process with multiple choices and supportive reasoning for selection. The well primarily discussed in this paper, was a horizontal well in a tight gas field. The knowledge gained from the multiple fishes in the case study horizontal well, streamlined future choices in BHA selections for similar fishes. As an operator, having the flowchart encourages more discussion with the service company, and supports the engineers in planning operations.

Post-fracturing cleanup and production revival in sub-hydrostatic wells can be challenging. The complexity is amplified in sub-hydrostatic multistage horizontal wells because, by the time the fracturing treatment is concluded, the gas phase of the energized fracturing fluids used during the initial stages of the fracturing treatment dissipates. In the subject sub-hydrostatic well, coiled tubing (CT) with a real-time telemetry system was utilized over a standard nitrogen lifting intervention utilizing conventional CT to revive a hydraulically fractured well due to its capabilities to enable real-time decisions using live bottom-hole data. Acid fracturing using an energized fluid treatment was conducted in the subject gas well completed with a multistage open-hole completion system using isolation packers and sleeves. As the subject well was sub-hydrostatic, it was decided to utilize the CT with real-time telemetry system to gain value from its associated downhole parameters during the cleanup phase to alleviate the chances of successfully lifting the well. The well was placed in an area with prolific offset producers; hence, there were high production expectations from this well. A review of the well indicated a decreasing trend of reservoir pressure from heel to toe of the lateral, possibly contributing to lower stresses and potential crossflow between stages. Hence, the diverter concentrations and volumes per stage and nitrogen rates were maximized for each new fracturing stage to attempt to create new fractures. Considering the challenges with the well, it was essential that the N2 lifting operation parameters should be optimized to enhance drawdown. It was decided to utilize CT with a real-time telemetry system to control drawdown parameters better and maximize the possibility of success. Real-time downhole pressure measurements were utilized to accurately identify the fluid gradient followed by real-time evaluation and monitoring of the well behavior during N2 lifting operations. The real-time downhole data collected enabled on-the-fly intervention optimization leading to transforming the well into an economic producer. The integrated post-treatment analysis workflow provided a robust insight into fracture treatment design and evaluation, reservoir imbibition perspective, openhole completion practices, and the importance of real-time telemetry for challenging interventions. The lessons learned that are presented in this paper could act as a guide to contribute to operational efficiency enhancements and cost savings in other projects.

Many retrograde condensate gas wells in field A, located offshore Malaysia, are underperforming or even idle because of calcium carbonate scale deposition and near-wellbore condensate banking. Previous treatments were performed without any adjustment of fluid placement across the multiple fractured zones due to the lack of technology enabling real-time downhole monitoring. Fluids could, therefore, be lost into depleted or high-water-cut intervals, leading to suboptimal treatment.Distributed temperature sensing (DTS) technology through optical fiber installed inside coiled tubing strings mitigates the risks related to blind acid pumping. The technology makes it possible in real time to monitor and adjust fluid placement and diversion efficiency to squeeze acid into target zones and maximize the treatment success.The first worldwide implementation of sandstone matrix acidizing using the DTS technology was performed on a well completed with four perforated and propped fractured zones. The main treatment fluid was designed to remove both types of formation damage: organic acid would attack the scale and alcohol would eliminate the condensate banking. The first challenge was the cleanout of hard carbonate scale from the wellbore, which was performed with a bottomhole assembly composed of a high-pressure rotating jetting tool and a real-time fiber-optic tension-compression sub enabling the coiled tubing unit operator to maximize the slack-off on scale and facilitate its removal. The second challenge was the depleted upper perforated and propped fracture interval detected by the DTS. If diversion was inefficient, all fluids would get lost into the upper zone. A diverter fluid system formulated with degradable fiber blended into viscoelastic-surfactant-based fluid was optimized based on expected downhole conditions, and two stages were successively squeezed into the highly permeable (130-Darcy) depleted upper interval before getting a good signature on the DTS surveys showing that this zone was temporarily plugged and that the main treatment fluid would be squeezed into the lower target zones.The post-treatment gas production was double what was expected. A memory production logging tool was run after the job. This confirmed the crossflow to the upper depleted zone during shut-in and showed 86% gas production from the two bottom intervals, which demonstrates the effectiveness of both the innovative stimulation process with DTS and the diversion with degradable fiber.

This study focuses on horizontal wells completed with pre-perforated liners installed in open holes, and which produce under sub-hydrostatic conditions. During workover operations, loss circulation materials (LCM) are routinely pumped, thus requiring coiled tubing (CT) cleanout interventions to enable well production afterwards. The sub-hydrostatic nature of the reservoir makes it challenging to maintain optimum bottomhole pressure (BHP) and have the ideal downhole conditions, without significant losses and with sufficient annular velocities, for an effective cleanout. During CT cleanout operations, the LCM plugging the formation may falsely create a perception that the well is able to sustain a column of fluid. However, as the LCM is cleaned out and the wellbore starts communicating with the reservoir, sudden fluid losses may occur, causing solids in the annulus to fall and leading to a stuck pipe scenario. Constant control of the balanced downhole conditions is therefore critical in such operations—yet frequently overlooked during job design. The use of real-time downhole pressure sensors thus not only ensure effective cleanout but also act as a stuck pipe prevention measure. Based on job executions in similar wells, several lessons learned were compiled. The ability to maintain optimum downhole conditions by adjusting liquid and nitrogen rates during cleanout has proven to be key to a successful cleanout. Additionally, in one of the wells where CT did get stuck, the team was able to prevent debris from falling, thus addressing the root cause, and facilitating the implementation of an effective contingency plan to get the pipe free. The need for live downhole monitoring is even more important when operating in the pre-perforated liner sections that are exposed to the open hole. Common designs calculate annular velocities based on the internal diameter of the liner, but in reality, the much bigger openhole diameter shall be taken into consideration, which result in much lower values of annular velocities in reality. Additionally, selection of the right bottomhole assembly (BHA) is critical for the overall system performance. In the presented case, the motor and mill configuration was observed to be more effective compared to a high-pressure rotary jetting tool. However, as the motor and mill combination creates significant vibrations while operating, it becomes critical to use a ruggedized version of the live downhole CT acquisition system to ensure maximum reliability. The observations compiled throughout operations enabled the development of best practices. Risks involved in a cleanout operation are often underestimated, especially in a well with a depleted reservoir. As more reservoirs face depletion in mature fields globally, the ability to clearly understand the downhole dynamics during such operations makes the difference between a successful job and a catastrophic failure.