Perpustakaan Digital ITB

Carbon Capture and Storage (CCS) is an important technology for reducing industrial CO2 emissions through long-term geological storage. Depleted oil and gas reservoirs are considered promising storage formations because of their proven sealing integrity and existing infrastructure. However, the large pressure reduction experienced during CO2 injection may induce Joule–Thomson (JT) cooling, which alters the thermodynamic behaviour of the injected fluid and should be considered during injection system design and operation.This study investigates the spatial distribution of the Joule–Thomson coefficient (?JT) in an integrated CO2 injection system and identifies the operating parameters governing JT cooling throughout the injection process. A steady-state integrated numerical model representing the complete CO2 flow path from the offshore pipeline to the reservoir perforation was developed to obtain local pressure and temperature conditions. The local Joule–Thomson coefficient was subsequently calculated using the Peng–Robinson Equation of State coupled with the Mak thermodynamic formulation. A one-factor-at-a-time (OFAT) sensitivity analysis was performed by varying six operating parameters, namely injection rate (50–150 kg/s), nitrogen impurity concentration (0–5 mol%), pipeline ambient temperature (15–35 °C), SSSV opening level (25–100%), valve opening time (0–300 s), and reservoir pressure (500–1500 psi). The results demonstrate that the thermodynamic response varies considerably along the injection system and is governed by different operating parameters at different locations. Injection rate produces the greatest influence on the upstream Pipeline, Wellhead Choke, and SSSV, whereas reservoir pressure predominantly controls the Joule–Thomson behaviour at the Perforation. Nitrogen impurity, ambient temperature, SSSV opening level, and valve opening time produce comparatively smaller or localized effects. Under most operating conditions, the Perforation consistently exhibits the highest cooling tendency, with ?JT remaining close to 1.0 °C/bar.Overall, the study demonstrates that Joule–Thomson cooling in an integrated CO2 injection system cannot be evaluated solely from pressure-drop magnitude. Instead, pressure, temperature, and real-fluid thermodynamic properties must be interpreted simultaneously to accurately characterize the local cooling behaviour of injected CO2. These findings provide a thermodynamic basis for evaluating cooling tendencies in integrated CO2 injection systems for geological carbon storage.