Perpustakaan Digital ITB

Due to increasing greenhouse gas (GHG) emissions, Carbon Capture Utilization and Storage (CCUS) systems are expected to become optimal technologies in reducing CO2 emissions to limit global temperature rise below 2°C. This technology can capture CO2 directly from the air and store it in reservoirs (International Energy Agency, 2019). Projections indicate that CCUS has the potential to reduce carbon emissions by up to 9% by 2050. Besides serving as carbon emission storage, CCUS also enhances the recovery factor of oil or gas fields. In this context, CCUS is divided into Enhanced Oil Recovery (EOR) and Enhanced Gas Recovery (EGR). Although research in Indonesia focuses more on oil fields than gas fields, it is crucial not to overlook the potential application of CCUS in gas fields in the future. Moreover, in response to increasing energy demands, the Indonesian government has set ambitious production targets for 2030, aiming for 1 million barrels of oil equivalent (MMBOE) and 12 billion standard cubic feet per day (BSCFD) of natural gas. This study aims to evaluate the most optimal injection parameters for CO2-EGR implementation to enhance recovery factors and project economics using compositional modeling. These parameters include CO2 injection rates and the location of injection well perforations to enhance production well recovery factors and are analyzed from an economic perspective. The study utilizes a synthetic reservoir model with heterogeneous reservoir properties based on data from the limestone gas reservoir of “FALA” field in West Java Province, Indonesia, consisting of four wells—three production wells and one injection well. Simulations are conducted for a 17-year production period from January 1st, 2027, to January 1st, 2044, with model initialization using SLB Petrel and ECLIPSE software, and third-party software such as IPM Prosper and PVTP. The study findings demonstrate that the investigated injection parameters play a crucial role in determining gas recovery factors and CO2 breakthrough times. Injections are scheduled when gas production rates decline from their plateau period, starting on January 1st, 2040. Higher injection rates, such as 60 MMSCFD, show improved net gas production results but tend to have earlier breakthrough times compared to lower injection rates like 40 MMSCFD and 50 MMSCFD. Injection well perforations in the gas zone also yield higher recovery factors compared to perforations in the aquifer zone but typically experience faster breakthrough times than injections in the aquifer zone. However, these results are also supported by economic analysis, where cases with higher injection rates and perforation in the gas zone yield the highest Net Present Value (NPV), namely Case C of 903.55 MMUSD. The NPV values obtained are relatively overestimated due to simplifications in parameter assumptions and economic costs. Nonetheless, these results sufficiently depict the most optimal and economic scenarios from the CO2-EGR study on the “FALA” field.