Addressing Flow Assurance and Annulus Pressure Management Challenges in HPHT Well

Abstract HPHT well required open-up after being drilled, completed, and unloaded without impacting topside facilities and existing wells. Flow assurance (i.e., hydrates formation prediction), potential wellhead growth, and annulus management during well open-up required a detailed study. The paper describes a comprehensive approach in HPHT gas well management, involving flow assurance evaluation, backpressure modelling, annulus management plan preparation, and implementation of unified workflow to minimize associated risks and unlock technical potential of HPHT well. A comprehensive plan was established to address potential backpressure evaluation from HPHT well to existing wells producing from reservoirs with lower formation pressures; flow assurance prediction via hydrates formation modelling; annulus pressure management via nitrogen cushion injection and installation of pressure bleeding lines for respective annuluses; topside management via wellhead growth monitoring during open-up. Numeric Simulation was carried out to predict potential hydrates formation due to Joule–Thomson effect across the choke and run sensitivity cases for concentrations of hydrate inhibitors and injection rates. Wellhead growth evaluation was carried out via modelling to address risks associated with topside facilities. Based on hydrates modelling prediction, a 4 bbl of methanol solution was selected for injection at 0.0277 m3/h rate via wellhead to minimize risks associated with hydrates formation due to Joule–Thomson effect across the choke during the early stage of well open-up until pressure drop across the choke reduces and flowline temperature raises. Nitrogen was injected in the Annulus A (at 200 psig) as a cushion and monitored throughout the well bean-up. Maximum allowable and maximum operating pressures were established for Annulus A, B, and C with bleeding lines connected to reduce any potential pressure increase due to thermal expansion. Based on the thermal growth study, the safe limits of minimum 3" and maximum 10" of wellhead growth, were monitored and adhered to safeguard topside facilities and operations. All findings and results of multidisciplinary studies were summarized in a comprehensive well open-up procedure with critical precautions put in place. As a result, HPHT well open-up successfully commenced in a safe manner, unlocking the well technical potential of 75 MMscfd of gas and 1900 blpd of condensate rate. The success of this pilot is crucial for future HPHT gas well developments with flow assurance and annulus pressure management challenges. Current approach summarizes the best practices and lessons learned from the successful implementation of hydrates management via methanol injection, backpressure evaluation, and wellhead growth prediction via numerical modelling, and annulus pressure build-up management via nitrogen cushion injection during HPHT gas well start-up that can be applied to future HPHT developments.