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Hadziqul Abror
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Program Studi Teknik Perminyakan, Fakultas Teknik, Universitas Jember Jl. Kalimantan Tegalboto No.37, Krajan Timur, Sumbersari, Kec. Sumbersari, Kabupaten Jember, Jawa Timur 68121.
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Journal of Sustainable Energy Development
Published by Universitas Jember
ISSN : -     EISSN : 30482585     DOI : -
Core Subject : Science, Engineering,
Energy Engineering
The Journal of Sustainable Energy Development is the official scientific journal of Petroleum Engineering, Faculty of Engineering, University of Jember for the dissemination of information on research activities, technology engineering development and laboratory testing in sustainable energy development. The focus and scope of JSED as follows: Oil and Gas Technology: Production, Reservoir, and Drilling Technology, Enhance Oil Recovery Geothermal Technology: Reservoir Characterization and Modeling, Development of Productivity-Enhancing Methods, Plan of Vevelopment Earth Science: Geology, Geophysics, Geochemical Renewable Energy: Wind energy, Hydro energy, Solar cell energy, Biomass
Arjuna Subject : Energi (semua kategori) - Energi Terbarukan, Keberlanjutan dan Lingkungan
Articles 29 Documents
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Optimasi Produksi Menggunakan Injeksi CO2 dan Penerapan Sistem Carbon Pricing Reservoir X Wulan, Nanda; Eklezia Dwi Saputri, Eriska; Laksmita Sari, Riska
Journal of Sustainable Energy Development Vol. 3 No. 1 (2025): Journal of Sustainable Energy Development (JSED)
Publisher : Petroleum Engineering, Faculty of Engineering, University of Jember

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Abstract

Indonesia tercatat sebagai salah satu negara penyumbang emisi gas CO₂ terbesar di dunia dengan total emisi mencapai 1,3 Gt di mana 50,6% berasal dari sektor industri migas. Oleh karena itu, Pemerintah Indonesia berkomitmen untuk menurunkan emisi GRK sebesar 29%. Penelitian ini bertujuan untuk mengurangi emisi GRK dengan menerapkan sistem carbon pricing pada perhitungan keekonomian dan penggunaan metode injeksi gas CO2 pada reservoir X. Selain itu, metode injeksi CO2 diharapkan nantinya dapat mengoptimalkan produksi minyak pada reservoir. Injeksi CO₂ di reservoir X dan penerapan sistem carbon pricing menggunakan skema Production Sharing Contract (PSC) Gross Split dirancang dengan data asumsi yang memiliki karakteristik minyak ringan (°API 35) dan batuan sandstone dengan kedalaman 10.000 ft. Pada awal produksi, reservoir X mengalami penurunan yang signifikan akibat aquifer support yang lemah, sehingga diterapkan Enhanced Oil Recovery (EOR) dengan injeksi CO₂ secara miscible dan immiscible. Penelitian ini menggunakan 3 skenario yang nantinya disimulasikan dan dibandingkan hasil perolehan terbaik. Skenario 3 merupakan skenario terbaik dengan menginjeksikan 1 sumur produksi dan 2 sumur injeksi yang menunjukkan peningkatan kumulatif produksi minyak lebih besar dari simulasi basecase, diperoleh nilai sebesar 7,6 MMBBL dengan recovery factor sebesar 55% dan penurunan water cut hingga 91%. Selain itu, hasil perhitungan keekonomian dengan menerapkan sistem carbon pricing menghasilkan NPV sebesar 786.678,21 USD, IRR sebesar 11%, dan Pay Out Time (POT) selama 7,4 bulan yang mengindikasikan kelayakan ekonomi proyek bagi kontraktor. Penelitian ini memberikan triple-win solution dengan meningkatkan produksi minyak, mendukung target nasional pengurangan emisi karbon, dan memberikan keuntungan ekonomi.
Studi Simulasi: Pengaruh Soaking Time dan Injection rate Terhadap Peningkatan Recovery Factor dalam Injeksi CO2 Huff & Puff Pada Sumur X Sahtria panjaitan, sahtria panjaitan; Triono, Agus; Eklezia Dwi Saputri, Eriska
Journal of Sustainable Energy Development Vol. 3 No. 1 (2025): Journal of Sustainable Energy Development (JSED)
Publisher : Petroleum Engineering, Faculty of Engineering, University of Jember

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Abstract

CO₂ Huff & Puff injection is an effective enhanced oil recovery (EOR) method to boost production in declining reservoirs. This study focuses on simulating CO₂ Huff & Puff injection in Well X, SKW Field, by analyzing injection parameters such as soaking duration and injection rate. The simulation was conducted without history matching but included sensitivity analysis to evaluate reservoir performance. Seven soaking time variations (5–35 days) were tested, with 20 days yielding the highest Recovery Factor (RF) of 4.064%. Injection rate variations ranged from 1×10⁶ to 1.6×10⁶ ft³/day, with 1.4×10⁶ ft³/day achieving the highest RF increase of 4.070%. Soaking time and injection rate significantly impact oil recovery; however, excessive soaking leads to gravity segregation, reducing oil displacement efficiency. The optimal combination for maximizing recovery in Well X is a 20-day soaking time with a CO₂ injection rate of 1.4×10⁶ ft³/day. Keywords: CO2 Injection; Huff &Puff, Soaking Time, Injection rate
Studi Prediksi Porositas Dengan Menggunakan Metode Deterministik dan Machine Learning Pada Lapangan “X” Hafwandi, Babas Samudera
Journal of Sustainable Energy Development Vol. 3 No. 1 (2025): Journal of Sustainable Energy Development (JSED)
Publisher : Petroleum Engineering, Faculty of Engineering, University of Jember

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Abstract

Porosity is one of the most critical parameters in reservoir characterization, as it directly influences hydrocarbon storage capacity. Accurate porosity prediction becomes even more essential in fields with limited core data, such as Field “X”, located in the South Sumatra Basin. This study compares two different porosity prediction approaches: a deterministic method based on well log interpretation using NPHI and RHOB logs, and various Machine Learning (ML) algorithms, including Random Forest (RF), K-Nearest Neighbor (KNN), Gradient Boosting (GBR), AdaBoost (ADA), Support Vector Machine (SVM), and Decision Tree (DT). Data preprocessing involved feature selection using Pearson, Spearman, and Kendall correlation coefficients to identify the most influential log parameters. The dataset was then divided into training (70%) and testing (30%) subsets. Model performance was evaluated using Mean Absolute Error (MAE) and Root Mean Square Error (RMSE). The deterministic method yielded an MAE of 0.0658 and RMSE of 0.0906, while the best ML model, Random Forest, achieved an MAE of 0.0329 and RMSE of 0.0434 on the testing dataset. In conclusion, Machine Learning, especially the Random Forest model, proves to be a more reliable and accurate tool for porosity prediction in geologically complex fields, offering significant potential for enhancing reservoir modeling and field development planning.
EVALUASI KINERJA POMPA PCP DAN IDENTIFIKASI KONDISI UNDERLOAD MENGGUNAKAN EFICIENCY VOLUMETRIC PADA VARIASI FREKUENSI OPERASI Irsyad Afi Asyhari Putra; Hadziqul Abror
JSED Vol. 3 No. 2 (2025): Journal of Sustainable Energy Development
Publisher : Universitas Jember

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.19184/jsed.v3i2.60000

Abstract

The decline of reservoir pressure and the increase of water cut in mature oil fields often lead to a decrease in oilproduction, making wells uneconomical under natural flow conditions. Progressive Cavity Pump (PCP) is an artificiallift system commonly applied in such conditions due to its characteristics as a positive displacement pump. This studyaims to evaluate the performance of the existing PCP in Well X of Field Z and to identify underload conditions usingvolumetric efficiency as the main indicator. The analysis was conducted using secondary data through InflowPerformance Relationship (IPR) analysis with the Vogel method, nodal analysis, and evaluation of PCP performanceunder operating frequency variations ranging from 30 Hz to 60 Hz. The results show that Well X is producing atapproximately 90% of its maximum inflow capacity, indicating that reservoir inflow is the main limiting factor forproduction increase. Although increasing the operating frequency raises total fluid production, the volumetric efficiencydecreases from 85.3% at 30 Hz to 56.1% at 60 Hz, indicating underload conditions caused by the imbalance betweenpump capacity and reservoir inflow capability. The study concludes that the underload condition of the PCP is not dueto improper pump design but to limited reservoir inflow, and volumetric efficiency is an effective parameter for identifyingunderload in PCP operations.
PENGEMBANGAN LAPANGAN TGB DENGAN PARAMETER PENAMBAHAN SUMUR DAN KEEKONOMIAN DENGAN SIMULASI RESERVOIR Putri, Devita; Abror, Hadziqul
JSED Vol. 3 No. 2 (2025): Journal of Sustainable Energy Development
Publisher : Universitas Jember

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.19184/jsed.v3i2.60001

Abstract

The Tarakan Basin in North Kalimantan is a key hydrocarbon province featuring the Meliat, Tabul, Santul, and Tarakan formations, serving as source rock, reservoir, and seal. Before 2006, the area, especially Bunyu Island, was considered a greenfield due to limited data. This changed with the successful drilling of exploration well A-01 in 2006, which confirmed oil presence in the Tabul and Meliat Formations. This study evaluates development scenarios for the TGB Field using reservoir simulation and economic analysis under a Production Sharing Contract (PSC) with a Cost Recovery scheme. CMG 2021 software was used, based on production history, petrophysical data, geological models, and pressure history. Results show that additional wells significantly improve recovery. The base case with only well A-01 yields 562,188 STB (RF 1.6%). Scenario 1 raises production to 2.99 million STB (RF 8.65%), Scenario 2 to 4.29 million STB (RF 12.38%), and Scenario 3 to 4.59 million STB (RF 13.25%). Although Scenario 3 has the best technical result, Scenario 2 is the most economically viable, with a contractor NPV of USD 1.67 million, IRR of 12%, and pay-out in 7.82 years. It also provides significant government revenue of USD 307 million.
ANALISIS PENGARUH LAJU INJEKSI CO2 KONTINU DAN IMPURITAS TERHADAP RECOVERY FACTOR LAPANGAN DF dheafilla-02; Sari, Riska Laksmita
JSED Vol. 3 No. 2 (2025): Journal of Sustainable Energy Development
Publisher : Universitas Jember

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.19184/jsed.v3i2.60002

Abstract

This study focuses on evaluating the impact of varying continuous CO₂ injection rates and CO₂ impurity contents, such as N₂ and CH₄, on the Recovery Factor (RF) in the DF Field. Simulations were conducted using reservoir simulation with CO₂ injection rates of 1.3 MMSCFD, 2 MMSCFD, 3 MMSCFD, and 4 MMSCFD, as well as variations in CO₂ impurity mixtures, namely CO₂ 90% + N₂ 10%, CO₂ 90.1% + CH₄ 9.9%, and CO₂ 89.8% + N₂ 5.1% + CH₄ 5.1%. The results show that increasing the CO₂ injection rate is directly proportional to an increase in the recovery factor, with the highest recovery factor of 22.00% achieved in the 4 MMSCFD injection scenario. The effect of CO₂ impurities is evident in the scenario with N₂, which increases the Minimum Miscibility Pressure (MMP), potentially reducing sweep efficiency, while CH₄ has a moderate effect on the recovery factor and does not significantly reduce efficiency. The combination of CO₂ + N₂ yields the highest recovery factor at a 4 MMSCFD injection rate, reaching 17.00%. These results indicate that selecting the appropriate injection rate and controlling CO₂ impurities play a crucial role in enhancing oil production in heterogeneous reservoirs. The conclusion of this study is that choosing the optimal injection scenario can significantly improve oil recovery while minimizing operational risks related to sweep efficiency and fluid mobility in the reservoir.
Simulasi Kinerja Enhanced Oil Recovery (EOR) dengan Polymer dan Solvent CO2 pada Sumur Injeksi di Lapangan Norne Segmen C Arik; Eriska Eklezia Dwi Saputri
JSED Vol. 3 No. 2 (2025): Journal of Sustainable Energy Development
Publisher : Universitas Jember

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.19184/jsed.v3i2.60003

Abstract

The threat of an energy crisis driven by declining production from conventional wells and depleting global oil reserves can be mitigated through Enhanced Oil Recovery (EOR), which has the potential to increase production by 30-60%. This study evaluates the potential application of EOR using polymer and CO2 solvent injections in Segment C of the Norne Field, Norway. The primary objective of this study is to determine the recovery factor, observe the vertical and areal dynamics of oil saturation, and compare the effectiveness of both methods. Continuous injection simulations were applied to wells C-1H, C-2H, C-3H, and C-4H. The results indicate that the oil recovery factor from polymer injection in well C-2H reached 49%, outperforming both the CO2 solvent injection (46.45%) and the basecase scenario (46%). Meanwhile, the gas recovery factors for the basecase, polymer, and CO2 solvent were recorded at 70.50%, 61%, and 71%, respectively. Furthermore, fluid movement evaluation shows that polymer injection provides a more uniform areal sweep efficiency both macroscopically and microscopically, unlike the CO2 solvent, which is prone to segregation within the reservoir. In conclusion, the continuous polymer injection method demonstrates superior performance compared to continuous CO2 solvent injection in the Norne Field Segment C.
A Studi Keekonomian Pengembangan Lapangan Gas NE Menggunakan PSC Cost Recovery dan Gross Split: Economic Study of NE Gas Field Development Using Cost Recovery and Gross Split PSCs Eka Saputra, Nanda; Hadziqul Abror; Riska Laksmita Sari
JSED Vol. 3 No. 2 (2025): Journal of Sustainable Energy Development
Publisher : Universitas Jember

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.19184/jsed.v3i2.60004

Abstract

The NE Field is one of the fields that has produced gas since 1970 and was not developed again after that due to certain reasons. Currently, the NE Field will be developed again to support production results to achieve the national targets that have been announced. In the development of oil and gas fields, several analyzes are needed both technically and economically. In this study, before carrying out economic analysis, the things that were carried out were a review of potential reserves and estimates of NE field development. using the volumetric method, the total reserves for the NE Field were obtained at 274.32 BCF and after calculating the Recovery Factor, the Remaining Reserve was obtained at 215.46 BCF, then determining deliverability to predict production in order to achieve the target plateau rate that had been agreed upon according to the contract and by simulating 6 wells. obtained a plateau rate of 19.74 MMscf after deducting CO2 with cumulative gas production of 129 BCF and a Recovery Factor of 67%. After obtaining production, an economic analysis was carried out and it was found that PSC Cost Recovery was more profitable for the contractor with NPV results (US$ M) 87,310.06, IRR 46%, and POT 3.41 years for PSC Cost Recovery while for PSC Gross Split the NPV results were ( US$M) 69,323.11, IRR 28%, and POT 6.27 years. And in terms of sensitivity, PSC Gross Split is more sensitive than PSC Cost Recovery.
ANALISIS SENSITIVITAS PARAMETER INJEKSI GAS LIFT TERHADAP PERFORMA PRODUKSI SUMUR FT Ananda, farhan; Abror, Hadziqul
JSED Vol. 3 No. 2 (2025): Journal of Sustainable Energy Development
Publisher : Universitas Jember

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.19184/jsed.v3i2.60005

Abstract

Well FT is a multilayer oil well that is no longer able to produce under natural flow conditions due to insufficient reservoir pressure, as indicated by the absence of an intersection between the Inflow Performance Relationship (IPR) and Vertical Lift Performance (VLP) curves. To restore and optimize production, a continuous gas lift system was designed and evaluated using nodal analysis and PIPESIM simulation. The gas lift design successfully reduced the fluid column density in the tubing, lowered the bottom-hole flowing pressure (Pwf), and shifted the VLP curve to intersect with the IPR curve, enabling stable production. Sensitivity analysis was performed on key operating parameters, including gas injection rate, injection pressure, and injection depth, to determine the optimum operating conditions. The results show that an optimum gas injection rate of 3 MMSCFD provides the most effective production increase before efficiency declines. Deeper gas injection further enhances production by reducing Pwf, while an injection pressure of 600 psia was identified as the optimal condition, offering near-maximum production with improved operational stability. Overall, the implementation of continuous gas lift proved to be technically effective for enhancing the production performance of Well FT.

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