The plug-and-perf (PnP) method is widely used globally for multistage fracturing operations. With only a few jobs performed worldwide, coiled tubing (CT) assisted PnP operations in high-pressure/high-temperature (HP/HT) wells are largely uncharted and most challenging. The "A" field in India has HP/HT formations, with bottomhole temperature (BHT) of 310°F and reservoir pressure of 9,000 psi. Whereas the PnP method is widely used globally, there are few examples in wells with completion restrictions or whose downhole conditions dramatically increase depth inaccuracies and equipment damage. This study describes how to address challenges such as depth correlation (which affects plug-setting depth accuracy), low injectivity, completion restrictions, and heavy brines (which damage CT). To gain further understanding of operations, simulations are sensitized to identify solutions for pumping rates, HP/HT conditions, well kill fluid, milling, and cleanouts where obstructions hindered BHA penetration. The proposed best practices presented here are for primary CT operations involved in the complete PnP cycle, such as wellbore displacement, well dummy run-drift, setting the isolation plug and milling, acidizing using jetting tools, sand cleanout using gels having best performance in HP/HT environment and motor-mill runs with durable resistance in harsh environment, well kill (using 13.65-ppg calcium bromide), and nitrogen lift. The featured case studies describe operations including seven bridge plugs being set at accurate depths and milled after fracturing; cleanout of a 340-m sand column is also featured, as well as well kills with heavy brines. Optimized operational parameters such as CT speed, pumping rates, and the use of smaller outer diameter bottomhole assemblies doubled operational efficiency during those operations.

This paper shares the best practices for performing coiled tubing (CT) operations in high-temperature geothermal wells with major challenges such as live well challenges, scaling of pumping fluid, high surface temperatures causing damage to wellhead stack, and CT tag issues. Some geothermal wells have very high bottomhole temperature (BHT) of 550 to 600 °F and surface temperature of 350 to 400 °F, which possess many service quality and health, safety, and the environment risks. With limited CT geothermal interventions as compared to conventional operations, performing live well CT interventions can be highly risky. Because commonly available pressure control equipment (PCE) seal material is rated to 250°F, the biggest risk is damage to the surface CT equipment, which may result in a well control situation. Generally, the lead time is high, and it is expensive to use temperature seal material rated more than 250°F. A generalized design methodology was developed to check the CT job feasibility in a high-temperature geothermal well. To gain further understanding on the same, three cooling loop designs are compared in this study. Then, the best solution was simulated, implemented, and verified on some wells of "X" field. This design proved to be effective operationally and has reduced the risks for steam inflow into the PCE. For the case of scaling caused by pumping fluids at high temperatures, this was identified while performing CT operations in geothermal wells of X field. The scale deposited on the CT along with pumping fluid was sent for laboratory hardness and solubility analysis. The results were compared, and lessons learnt to prevent any scaling are discussed. Most of the geothermal wells are completed with a large-diameter completion (7-in., 9.625-in., and higher), which has a bigger flow area to accommodate high steam inflow. Using even a 2.875-in. CT in these wells presents issues of CT tagging at the completion-liner interface, lower annular velocities, and lifting capacity, among others. The best practices were developed on the job to identify the most efficient bottomhole assembly (BHA) design, reducing the probability of CT getting tagged at these depths.

Coiled tubing (CT) sand plug operations associated with multistage fracturing operations in high-pressure/high-temperature (HP/HT) wells are very challenging, in part because of the small number of such jobs that have been performed worldwide. The wells in "A" field in India have HP/HT formations, with a bottomhole temperature (BHT) of 310°F and a reservoir pressure of 9,000 psi. Although millable bridge plugs are preferred industry-wide, this case illustrates how sand plugs become a suitable alternate solution for multistage stimulation to address space limitations, equipment and completion restrictions, and small tubing sizes, even in challenging downhole conditions. This study provides solutions to operational challenges of low injectivity and completion restrictions, which preclude bullheading and use of conventional bridge plugs. Simulations were sensitized to identify the best solutions for sand settling time, HP/HT conditions, pumping rates, CT speeds, and cleanouts where calcite or scale deposits on sand hinder bottomhole assembly (BHA) penetration. Best practices are given for sand plug operations in challenging HP/HT environments; those best practices can be applied as a reference to design, prepare, and safely perform CT sand plug jobs in such conditions around the world. To address operational challenges in the cases presented here, the first three stages were bullheaded and the last two (a total 325-m sand plug) were placed using CT. Wireline was run to verify CT sand plug tag at ×200-m measured depth (MD). After the successful refracturing job, the 340-m sand plug was cleaned out, followed by acid spotting and squeeze using CT to rejuvenate the lowest zone. Strict application of the recommendations prevented the occurrence of operational contingencies, such as stuck CT, sand bridging, and settling of sand in surface equipment.

The wells in the "A" geothermal field located in the Philippines, have high bottomhole temperature (BHT) of 600°F and bottomhole flowing pressure (BHFP) of 2,000 psi. The productive section in this field has "shallow" and "deep" reservoirs which are separated by a low-permeability formation. The interaction between the reservoirs is hence limited except through the wells resulting in intrazonal flows under shut-in conditions. As observed with time, these flows have been upflows making the overall production very stable. However, in recent years, it has been found that the cooler fluid inflow from the shallow reservoir has relatively increased, causing reduction in production levels. Under flowing conditions, this has resulted in both flow instability and downflows in wells, which in turn have decreased the individual well production capacity. In order to activate and enhance well production, coiled tubing (CT) nitrogen lift operations were required to be performed to unload the cold water in geothermal wells, hence enhancing steam production. The wells in this field are completed with large completion sizes (7-in., 9.625-in., and 13.375-in.) and have high BHT (600°F), which makes conventional coiled tubing operations highly challenging. Because the coiled tubing operations in geothermal wells are limited as compared to the conventional operations, planning and executing these for the first time in the "A" field was challenging operationally and technically. As such, surface equipment failure risk was high, putting at risk successful coiled tubing operations. To gain further understanding of operations in high temperature and cold water downflow environments, CT simulations were combined with simulations from the geothermal reservoir to overcome modeling limitations. The outcome helped designing a new cooling loop system and allowed optimizing the nitrogen lift technique. As a result, two large-diameter geothermal wells were lifted safely with 2-in. coiled tubing in the Philippines.

Raageshwari gas field is located in RJ-ON 90/1 Block in western India with Cairn Oil & Gas, a vertical of Vedanta Limited as operator of the field. Multistage hydraulic fracturing is required to achieve commercial production from the highly laminated retrograde gas condensate reservoir. It has been observed in almost all wells that the top high PI zones produce a majority of the gas. The wells have a water column across bottom few fracs which prohibits production from these zones. Water unloading through increased drawdown was not successful because of higher PI of the upper fracs. Coiled tubing-based nitrogen lift of the water column is not commercially feasible. It is important to find a low-cost solution for water unloading since bottom zones account for approximately 30% of total gas in place. A solution has been developed using a customized velocity string design, which can unload the water while maintaining high well production. Conventional velocity strings are only installed in late life of gas wells when liquid loading is observed. These conventional designs limit the maximum rate to 2-3 MMSCFD and therefore cannot be used in Raageshwari gas field for water unloading as high individual well rates (8 to 12 MMSCFD) is required to meet field plateau production. After reviewing various options, an innovative and unique velocity string system design was developed which incorporates a customized surface spool and string hanging system. This customized design allows combined or independent gas flow conduits as described below: Through the annulus of velocity string and tubing when higher gas rates are required. Through the velocity string to facilitate liquid unloading due to high gas velocity. Production from both the conduits to meet higher demands than the annulus flow alone. Well integrity was assured by maintaining two independent barriers during commissioning, production phase and also during future string retrieval. This paper will discuss in detail the design considerations of the velocity string and surface hanger system to achieve liquid unloading while maintaining high rate gas production. It will also have details on the dual barrier selection process and the design customization that have been done to ensure cyclic liquid unloading and high rate gas production. This innovative velocity string design is technically a dual completion with a much lower cost and footprint. The same design can be implemented across a wide variety of applications to address well integrity issues, selective zonal production etc. The application of this design in Raageshwari field will ensure planned recovery of gas from the field and will also support plateau production phase. This design can be an efficient and economic technique to develop similar fields.