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Coiled tubing (CT) is widely used during sand cleanout applications for its multiple benefits, such as speed, cost effectiveness, minimum reaction time, efficient operations, the ability to perform live intervention cleanouts, etc. However, these benefits are difficult to achieve in complex, offshore, high-pressure/high-temperature (HP/HT), or big bore wells because of various operational constraints, such as weight, dimensions, wellbore trajectory, and completion design, resulting in increased expenditures and operation time for workover activities. This paper describes how these constraints were eliminated using a synergy of an innovative fluid system and engineering to perform a challenging, balanced sand cleanout treatment using 1.75-in. 5800 m long CT in ~500 m of a 7-in. 35-lbf casing section executed in a 5300-m deep HP/HT well. The deep HP/HT well had a minimum restriction of 2.56-in. in the upper completion limits, requiring large-diameter CT strings and a bottomhole assembly (BHA). Feasibility studies for use of a 1.75-in. CT vs. 2-in. CT string were performed, resulting in the selection of the 1.75-in. string. Another challenge was executing sand cleanout in a balanced condition, resulting in the selection of a saturated 13.1-lbm/gal potassium-formate (K-formate) brine. The combination of all three major constraints, a) 500-m long 7-in. section, b) use of 1.75-in. CT string, and c) use of saturated brine, made the cleanout design challenging, as sand cleanout with CT requires circulation rates, net particle rise velocity, friction pressures, viscosity, and fluid properties within the design envelope. However, the inversely proportional nature of such treatments means tuning of one property would decrease the operational feasibility of other properties. Based on results of several tests, a customized fluid recipe was designed containing a gelling agent that can become hydrated in saturated brine and remain stable at high temperatures. A compatible friction reducing agent was used to help reduce pumping friction to attain the desired annular fluid rate and velocity. A field test was performed with the designed fluid at surface with a CT string that was to be used for operations, confirming the effectiveness of the fluid recipe. Using downhole turbulence created by the tool, along with the custom-designed recipe in combination with wiper trips, the necessary design parameters were achieved for the cleanout operation, resulting in a) effective sand cleanout with ~98% efficiency, b) reduced operating hours, c) cost savings on workover operations, d) safer operation by keeping the well in a balanced condition, and e) a contingency action in place for screenout during fracturing treatments. The procedure described in this paper, along with lesson learned, can be applied in similar applications to help optimize results and overcome related challenges.

Coal Bed Methane (CBM) development in India has emerged as one of the cleanest solutions to the fuel energy requirements of this energy-starved country. Favorable market scenarios and lucrative gas prices are enabling operators in this business to target aggressive well-completion schedules. This study discusses the techno-economic benefits realized by the operator company of using combined coiled tubing (CT) deployed hydrajetting and fracturing services instead of conventional wireline perforations in CBM wells. The service company introduced a unique fracturing service that integrates six processes – depth correlation with CT, hydra-jet perforation, hydra-jet fracture initiation, hydraulic fracture stimulation, zonal isolation using a sand plug, and wellbore cleanout using CT. It completes these processes in one single trip-in-hole, making the service cost and time efficient and eliminating the use of wireline for perforating and setting bridge plugs in the well which requires multi-stage fracturing. The technology in use, lessons learned, and knowledge gained from operations in India are shared in this paper. The process employs a customized CT bottom-hole assembly (BHA) at the core of its service. Customized engineering solutions for hydrajetting can be developed based on casing specifications, cementing conditions, and stimulation design. The principle of hydrajetting perforations and the BHA details are discussed along with its benefits over the alternative techniques. The experience gained during operations allowed the service company to optimize jetting flow rates, differential pressures, and back pressures to improve its operational efficiency and also allow maximum proppant to be placed into the formation being stimulated. Implementing the lessons learned increased the hydrajetting tool life from 25-30 sets of perforation to about 40 per tool. The paper also discusses job design improvements implemented to prevent sanding up the wellbore leading to stuck CT. Finally, the paper discusses the economic benefits achieved by the operator company leading to increased productive time and a faster rate of well completion. CBM fields require excessive dewatering before they break out gas and become commercially viable projects. The technology discussed in this paper enables the operators to put the maximum number of wells on production, in a shorter period maximizing the Net Present Value (NPV) of the asset.

Gas hydrate formation during the drilling and completion phase can add significant operational costs in a deepwater environment. In an ultra-deepwater well off the east coast of India with a water depth of 2830 mMD, a hydrate plug was discovered during well-killing operations after a well test. Multiple attempts to remove the plug using cyclic pressurization/depressurization failed, and a Coiled Tubing (CT) intervention was required to mill out the hydrate plug. A Coiled Tubing Lift Frame (CTLF) was rigged up to accommodate the CT stack inside the derrick then CT was deployed with a milling Bottom-Hole Assembly (BHA). This BHA comprised of an even-walled stator assembly motor and Hurricane mill bit. Heated brine with 6%-30% glycol was the fluid recipe for the job with the glycol concentration at different pressure and temperature conditions calculated based on data derived from the methane hydrate formation curve and Hammerschmidt's equation. The engineering plan also incorporated the backpressure and fluid temperature selection criteria based on available reservoir and well test data. Milling was started and operating parameters were maintained to achieve a controlled rate of penetration. Since hydrate formation is not homogeneous, backpressure was maintained throughout the job to regulate the expansion of any gas pockets between the plug and prevent solid hydrates from being propelled to the surface during milling. The "less-aggressive" Hurricane mill bit was selected to prevent any large chunks of solid hydrate from getting dislodged from the plug. An even-walled stator was selected as it provides higher operating limits and is more resistant to deformation and degradation. The temperature of pumping and return fluids was constantly monitored to ensure sufficient thermal energy downhole to prevent hydrate re-formation. Since bottom-hole temperatures were close to the freezing point of water, fluid was continuously pumped at a minimum rate during CT trip-in to keep the stator elastomer lubricated and "heated". The 600m hydrate plug inside the riser string was milled-out in less than 24 hours, following which the CT did not encounter any obstructions to the depth of the sub-sea test tree (SSTT) at 2830 mMD. Pressure communication was established with the well and the job was concluded. Removal of gas hydrate plugs is a technically challenging and operationally complex job. Furthermore, available literature and case histories on this topic are sparse. This paper presents key learnings from both the planning and execution stages which made this challenging job a success. The paper aims to serve as a reference for operators and service companies to plan, develop and execute similar CT well intervention solutions.