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2024 TA PP MUHAMMAD NAUFAL AQIL ZUHDI 1-ABSTRAK
Terbatas  Suharsiyah
» Gedung UPT Perpustakaan
Terbatas  Suharsiyah
» Gedung UPT Perpustakaan
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.