Stimulation Design and Execution of a HT Offshore Gas Well and its Flowback After an Extended Shut-In: A Case Study of a New Single Stage Sandstone Acid System

Abstract Operators frequently face challenging decisions when aiming to enhance performance—often weighing the benefits of stimulation against the option of plugging and abandonment. A Malaysian operator encountered such a challenge on a depleted offshore gas well, where the stimulation design was particularly complex due to a high bottom-hole static temperature of 310°F and elevated reservoir clay content reaching up to 21% in certain zones. Additionally, the treatment needed to address multiple suspected formation damage mechanisms to restore production. After careful evaluation, the decision was made to proceed with matrix stimulation. The engineering team undertook the challenge of designing a tailored, multi-phase remedial treatment. The workflow began with a systematic diagnosis of the primary formation damage mechanism requiring remediation: fines migration, scale deposition, and completion damage. Next, a five-phase treatment design plan was developed, accounting for the challenging reservoir conditions and aiming to minimize the risk of further formation damage: Phase I – Tubing Soak: Targeting rust and inorganic scale removal in the tubing.Phase II – Flowback of Tubing Soak: Ensured removal of loosened debris and scale prior to stimulation.Phase III – Step Rate Test: Assessed injectivity and fracture gradient.Phase IV – Diverted Single Stage Sandstone Acid (SSSA): Addressed fines migration and completion damage.Phase V – Flowback of Treatment Fluids: Intended to recover injected fluids and evaluate treatment effectiveness. Phases I through IV were executed successfully. The well responded positively, with distinct pressure declines during the acid stages indicating effective damage removal, and pressure increases during diverter stages confirming successful diversion. Unfortunately, Phase V of the treatment could not be completed as planned, and the well was shut-in after only a partial flowback, leaving the Single Stage Sandstone Acid (SSSA) treatment in the formation for an extended period of nine months. SSSA is a novel fluid technology designed to mitigate primary, secondary, and tertiary damage reactions in sandstone formations. However, the prolonged shut-in under high-temperature conditions in a clay-rich reservoir were beyond what the fluid was designed for. Anticipating potential formation damage, the engineering team prepared a contingency plan for restimulation following flowback. To assess the impact of the extended shut-in, a laboratory study was initiated to evaluate the effect of SSSA exposure on reservoir core samples at elevated temperatures. These experiments were constrained by the difficulty of replicating long-duration shut-ins under high-temperature conditions in a lab setting. Nonetheless, the study revealed no observable damage to the core samples after a 5-hour shut-in at reservoir temperature. Three months into the shut-in, additional funding became available, allowing the team to inject a small volume of nitrogen to displace any potentially corrosive fluids from the tubulars. Preparations were then made for a full flowback following the monsoon season. After a total of nine months of shut-in, the well was successfully flowed back. Remarkably, following the initial clean-up period, the well exhibited sustained production rates with an observed increase in the most damaged reservoir's zonal contribution. The treatment was deemed a success, and the contingency plan for restimulation was no longer required.