23 CHAPTER III METHODOLOGY AND CASE STUDY III.1 Research Methodology The methodology used in this thesis is shown in Figure 3.1 below. Start Literature Review Scientific References PVT Modelling Fluid PVT Case B (CO2 + Impurities) Fluid PVT Case A (Pure CO2) Fluid PVT Case C (CO2 + Impurities) CO2 Pipeline Modelling Pipeline Network Model for Case B Pipeline Network Model for Case A Pipeline Network Model for Case C Simulation Error Check Pipeline Simulation Result Analysis Finish If errof occured If no error Case Study Figure 3.1. Thesis Methodology 24 III.2 Case Study and Data The data case used in this study was obtained from “LAB” gas field. “LAB” gas field is a giant gas field located in Block “X”, which is located around 201.8 km or 662,073.5 ft from nearest island with water depth in the field ranges from 400 – 800 m (MSL) with southern boundary of the Block “X” is adjacent to the Indonesia – Hindia Ocean border. Figure 3.2. “LAB” Field Schematic Figure 3.3. Pipeline Bathymetry and Ambient Temperature Data Based on the reserve re-certification for “LAB” field, total proven and probable reserves are around 18.54 TCF with recovery factor as 70.4% and contains high levels of associated CO 2. CO2 from LNG process needs to be injected back to reservoir to prevent CO2 emission than if CO2 is released into the atmosphere. Table 4.1 below shows the summary of “LAB” field reserves. 0 15 30 45 60 75 90 105 -6000 -5000 -4000 -3000 -2000 -1000 0 1000 0 200,000 400,000 600,000 800,000 Ambient Temp. (degF) Geometry (ft) Pipeline Length (ft) Geometry (ft)Ambient Temp (degF) 25 Table 3.1. Summary of Reserve Certificationfor “LAB” Field Reserve Type Amount Proven Reserve 13.99 TCF Probable Reserve 4.55 TCF Recovery Factor 70.4% The dehydrated CO2stream from the onshore CCS system is transported to the CO2 injection well at the CO2reservoir (“LAB” field aquifer) through the CO2pipeline. The bathymetry of the CO2pipeline is identical to that of GEP, considering that the CO2pipeline will be laid together with GEP and consists of two parts, 3.9 km as an onshore part and 197.9 km as an offshore part with pipeline ID 14 in. Pipeline inlet pressure from compressor outlet are 186 –225 bar to keep above minimum pipeline operation pressure and avoid multiphase flow. Figure 3.4. Subsea Configuration for “LAB” Field The PVT data utilized in this study is sourced from the original dataset provided by the "LAB" Field. Subsequent inquiries involved conducting simulations with varying compositions, as depicted in Table 3.2, in order to ascertain the impact of water content on the corrosion rate within the pipeline. 26 Table 3.2. CO2 Composition for “LAB” Field Composition A Composition B Composition C Composition mol% Composition mol% Composition mol% CO2 99.784 CO2 99.284 CO2 100 N2O 0.0002 N2O 0.0002 N2O 0 CH4 0.0935 CH4 0.0935 CH4 0 C2H6 0.0098 C2H6 0.0098 C2H6 0 C3H8 0.0031 C3H8 0.0031 C3H8 0 i-C4 0.0006 i-C4 0.0006 i-C4 0 n-C4 0.0009 n-C4 0.0009 n-C4 0 C5 0.001 C5 0.001 C5 0 C6 0.0001 C6 0.0001 C6 0 C7 0 C7 0 C7 0 C8 0 C8 0 C8 0 C9 0 C9 0 C9 0 Benzene 0.0574 Benzene 0.0574 Benzene 0 Toluene 0.0212 Toluene 0.0212 Toluene 0 Ethyl Benzene 0.0004 Ethyl Benzene 0.0004 Ethyl Benzene 0 Xylenes 0.0022 Xylenes 0.0022 Xylenes 0 H2S 0.0132 H2S 0.0132 H2S 0 H2O 0.0122 H2O 0.5122 H2O 0 Tri-Ethylene Glycol 0.0002 Tri-Ethylene Glycol 0.0002 Tri-Ethylene Glycol 0.