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.

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.

Excessive sand production is the most common problem in both upstream & downstream processes in oil & gas production facilities. In Peninsular Malaysia, several methods were introduced to resolve this problem ranging from choke management, wellbore sand cleanout and even utilizing screen technology to keep the sand in the formation. However, all those methods are still not considered to be an effective solution to get a long lasting permanent result. By utilizing the furan resin as a sand consolidation treatment chemical, emphasis is given to solve the sand issues from the matrix formation side instead of focusing on the wellbore side as typically done. This results in a treatment that was previously almost impossible to execute but now ingeniously made possible. For every chemical treatment, the challenge lies in how to ensure it will effectively treat the targeted zone especially in multi layered formations which is a characteristic of most of Peninsular Malaysia's fields. This paper discusses the success story of this sand consolidation treatment utilizing Coil Tubing as a fluid conveyance tool combined with an inflatable packer to selectively treat the targeted zone. The furan resin properties will also be discussed as one of the key success factors in this sand control method for one of Malaysia's most challenging fields.

The most challenging clean out work in the world of coiled tubing (CT) is cleaning out inside a large diameter casing at a low bottom hole pressure. In West Seno field, this type of work is the basic requirement to be able to recover production,

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.