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INDONESIA
Scientific Contributions Oil and Gas
Published by LEMIGAS
ISSN : 20893361     EISSN : 25410520     DOI : -
Core Subject : Science, Engineering,
Chemical Engineering, Chemistry & Bioengineering Energy
The Scientific Contributions for Oil and Gas is the official journal of the Testing Center for Oil and Gas LEMIGAS for the dissemination of information on research activities, technology engineering development and laboratory testing in the oil and gas field. Manuscripts in English are accepted from all in any institutions, college and industry oil and gas throughout the country and overseas.
Arjuna Subject : Energi (semua kategori) - Teknologi Bahan Bakar
Articles 24 Documents
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Search results for , issue "Vol 48 No 3 (2025)" : 24 Documents clear
Transient Simulation to Analyze Wax Deposition and Flow Pattern Behavior Along Tubing Under Esp Installation and Gassy Well Condition Brian Tony; Steven Chandra; Rafael J.S. Purba; Muhammad Fadhlan Solihan; Ega Dimas Saputra
Scientific Contributions Oil and Gas Vol 48 No 3 (2025)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v48i3.1731

Abstract

Wax deposition is a common phenomenon that restricts flow in tubing, causing production decline. In the studied well, this decline is linked to wax thickness increasing from 0.0021 inches (Day 1) to 0.0114 inches (Day 7), occurring as fluid temperatures drop below 153.5°F. An Electrical Submersible Pump (ESP) is used to address this, but it impacts thermal conditions and flow behavior, especially in gassy wells. Therefore, a transient simulation is required to analyze wax deposition and flow behavior under ESP installation. This study performs a 7-day transient simulation using OLGA 2022.1.0 on the "X" well, a gassy well (700 scf/bbl GOR) with 38% wax content, utilizing a 70-stage DN610 ESP. Results show wax deposition begins on Day 1 (max 0.0021 inches) and thickens to 0.0114 inches by Day 7. Flow patterns vary along the tubing: stratified flow is dominant from the pump setting depth to KOP, while slug flow dominates from KOP to the tubing head. Annular flow was observed at the tubing head on several days. Sensitivity analysis revealed that more ESP stages result in more wax deposition. This is because the ESP increases the production rate; as more oil flows, more contained wax precipitates and deposits. The least wax was observed in the scenario with no ESP. This work demonstrates how ESP-induced liquid holdup and slug/annular transitions accelerate wax deposition and emphasizes the importance of transient simulation in predicting production risks.
Real Data-Driven Seismic Low Frequency Extrapolation: A Case Study from The Asri Basin, Java Sea, Indonesia Ignatius Sonny Winardhi; Asido Saputra Sigalingging; Ekkal Dinanto
Scientific Contributions Oil and Gas Vol 48 No 3 (2025)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v48i3.1748

Abstract

The Asri Basin, located in the Java Sea, Indonesia, is a significant hydrocarbon province with regions that remain underexplored. The available legacy seismic data, however, are limited in quality, particularly due to their narrow frequency bandwidth and the absence of low-frequency components. This limitation poses a significant challenge for advanced seismic imaging techniques such as Full Waveform Inversion (FWI), which rely low-frequency data to generate accurate and reliable subsurface models. This study aims to reconstruct the missing low-frequency (<10 Hz) components from the band-limited seismic data to enhance the applicability of FWI. A real-data-driven, self-supervised learning approach for low-frequency extrapolation is implemented to address this challenge. Using a modified U-Net architecture, the framework is trained directly on the available band-limited seismic data, eliminating the need for synthetic or labeled datasets. The self-supervised workflow employs a frequency-specific masking strategy that enables the model to learn and predict the missing low-frequency content from higher-frequency inputs. The results demonstrate that the proposed method effectively recovers low-frequency signals, achieving accurate reconstruction down to <5 Hz, reducing residual amplitudes compared to conventional methods, and preserving the mid-to-high frequency spectrum. This approach provides a promising solution for overcoming data limitations and mitigating cycle-skipping issues in FWI applications within the Asri Basin and comparable geological settings.
A Hybrid Probabilistic-Backpropagation Neural Network Solver for Nonlinear Systems in Reservoir Simulation Adrianto; Zuher Syihab; Sutopo; Taufan Marhaendrajana
Scientific Contributions Oil and Gas Vol 48 No 3 (2025)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v48i3.1751

Abstract

Reservoir simulation requires solving large, sparse systems of nonlinear equations, where iterative Krylov subspace solvers such as the conjugate gradient (CG), stabilized conjugate gradient (BiCG-STAB), and generalized minimal residual (GMRES) are widely applied. However, these methods often have limitations in terms of their stability and accuracy in nonlinear systems. This paper introduces a hybrid probabilistic backpropagation neural network (Prob-BPNN) solver that integrates neural-network-based initialization with probabilistic inference to improve robustness. The solver was benchmarked against CG, BiCG-STAB, and GMRES using two synthetic reservoir models with the GMRES solution at a tolerance of 10-10, serving as the reference solution. The results show that Prob-BPNN consistently achieved production profiles closely matching the reference solution, with errors of MAE ≤ 0.066, RMSE ≤ 0.071, MAPE ≤ 2.04%, and R2 ≥ 0.945. In contrast, CG and BiCG-STAB produced unstable and nonphysical results, with errors exceeding 292% and negative R2 values. In terms of computational performance, Prob- BPNN required 9.96 s in Case 1 and 45.90 s in Case 2, compared to 2.85 s and 1.53 s for GMRES, respectively. Although more computationally expensive, Prob-BPNN delivered convergence on the same residual order of magnitude (below 10-3) as GMRES while avoiding the severe instabilities observed in CG and BiCG-STAB. These findings indicate that the Prob-BPNN is preferable in applications where solver robustness and accuracy are critical, even at the expense of a higher execution time. Future research should focus on reducing computational overhead through parallelization and hybridization strategies to enhance the scalability of large-scale reservoir models.
4D Seismic Monitoring in Highly Populated Area: Study of CCUS in Sukowati Oil Field, East Java Oki Hedriana; Rachmat Sule; Wawan Gunawan A. Kadir; Asep K. Permadi; Djoko Santoso; Junita Trivianty; Dewi Mersitarini; Dimas Ardiyanta; Sofyan Sumarna
Scientific Contributions Oil and Gas Vol 48 No 3 (2025)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v48i3.1781

Abstract

 Indonesia is resolutely addressing climate change with a commitment to reduce carbon emissions by 29% in 2030, and we are on track to achieve net-zero emissions in 2050. This country acknowledges the important role of Carbon Capture, Utilization, and Storage (CCUS) in mitigating carbon emissions, especially from the energy sector, and at the same time increasing oil and gas production. This kind of approach is also well known as CO2-EOR (Enhanced Oil Recovery) and CO2-EGR (Enhanced Gas Recovery). Sukowati field is situated in the East Java Province and will serve as a pioneering CO2 Enhanced Oil Recovery (EOR) project aimed at revitalizing the field. This initiative focuses on increasing oil production while capturing and storing carbon dioxide (CO2), contributing to environmental sustainability. To ensure its success, a robust monitoring system must be implemented for real-time data collection and analysis, optimizing recovery processes and minimizing environmental impact. Monitoring activities deliver information regarding the CO2 injected into the reservoir and the risk of leakage into the surrounding injection region. Several methods are discussed for monitoring CO2 plumes, but in the subsurface, seismic methods stand out as the most promising option. However, despite their effectiveness, seismic methods are also among the most expensive to execute, necessitating significant investment in technology and expertise to ensure accurate and reliable data. 4D seismic, also known as time-lapse seismic, entails performing repeated seismic surveys over a designated area to monitor changes in the subsurface effectively. This imaging technique enables us to visualize the movement of CO2 plumes within the target formation and can identify alterations in the reservoir that may suggest a potential CO2 leak. A seismic survey before the injection is needed to create a baseline image of the subsurface target reservoir. Changes in velocity and amplitude are identified when the seismic waves encounter the CO2 plumes injected into the reservoir target. The challenges of performing a 4D seismic imaging survey in a densely populated area are social impact, the possibility of damaging infrastructure, high noise levels, and high operating costs, particularly if it uses a subterranean explosive (dynamite) as a source of seismic signals. To address these challenges, the study introduces a novel approach to designing irregular 4D seismic surveys. This method features a flexible acquisition layout that departs from traditional geometric symmetry. The survey utilizes a non-impulsive (vibrator) of semi-permanent seismic source and a highly sensitive, wireless seismic recording system. The irregular design is adaptively tailored based on the field's spatial characteristics, potential surface disruptions, and cost considerations. Despite not adhering to a conventional grid or orthogonal configuration, this approach ensures adequate offset and azimuth coverage necessary for detecting subsurface changes.
New Perspective of Unconventional Hydrocarbon Production With Emission Calculations Estherlita Elizabeth Syaranamual; Silvya Dewi Rahmawati; Ardhi Hakim Lumban Gaol
Scientific Contributions Oil and Gas Vol 48 No 3 (2025)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v48i3.1790

Abstract

The Paris Agreement aims to limit global temperature rise to below 2°C, with Indonesia committing to achieving net zero emissions by 2060. The oil and gas industry contributes around 15% of global emissions. On the other hand, as a developing country, we still depend on fossil fuels to meet our energy needs. Based on data from the IEA in 2015, Indonesia has 303 TCF of shale gas reserves that we use to meet future energy needs. This study conducts a case study on a shale gas field (field X) by calculating greenhouse gas emissions using engineering estimation methods. These calculations estimate methane and carbon dioxide emissions using activity data from each process and emission factors published in the 2021 API Compendium. Furthermore, this study analyzes emission control strategy scenarios so that field X produces fluids optimally with lower emissions. Based on the results of the field emission source study, emissions originate from two stages, namely pre-production, including normal operating processes such as mud degassing in drilling operations, flowback in hydraulic fracturing, and well test operations, followed by the production stage, including venting or gas release operations such as pneumatic controllers, casing gas vents, workover processes, and several gas processing tools such as glycol dehydration and glycol pumps. Thus, the total emissions generated during 12 years of production are estimated at 90.24 million tons of CO2e. A development scenario for field X is a combination scenario of 20% regulating the production flow rate and number of wells, resulting in an emission reduction ratio of 23% and a recovery factor of 28%.
Machine Learning-Based Prediction of Shear Wave Velocity: Performance Evaluation of Bi-GRU, ANN, and The Greenberg-Castagna Empirical Method Muhammad Raihan Ulil; Sonny Winardhi; Ekkal Dinanto
Scientific Contributions Oil and Gas Vol 48 No 3 (2025)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v48i3.1797

Abstract

Shear wave velocity (Vs) is recognized as an important elastic parameter for lithology and fluid identification in oil and gas exploration. However, Vs data is not always recorded in well logs. Various empirical approaches are often used to estimate Vs, but these methods show limitations in terms of accuracy and time efficiency. With technological advances, machine learning has become an effective and efficient alternative for predicting Vs from well log data. This study is utilizing the Bi-GRU model, a sophisticated artificial neural network specifically designed to process sequential data. This capability makes Bi-GRU particularly suitable for predicting log Vs data. Four Bi-GRU modeling scenarios are being developed with different hyperparameter configurations and are being compared with ANN models using two input variations: with and without Vp data. The results show that scenario 2 (Bi-GRU with five hidden layers, batch size 64, learning rate 0.005) is achieve the best performance, with R² values of 0.9787 (without Vp) and 0.9868 (with Vp). The MAE values obtained are being recorded as 9.36 (without Vp) and 11.22 (with Vp). Compared to shows ANN, MLR, and empirical Castagna methods, the Bi-GRU model show a more significant improvement in prediction accuracy. These findings are indicating that Bi-GRU have strong potential for accurately and efficiently predicting Vs from well log data.
Structure Evolution and Palinspastic Analysis of The Gurami-Tamiang Area, North Sumatra Basin, Indonesia Dumex Pasaribu; Benyamin Sapiie; Indra Gunawan
Scientific Contributions Oil and Gas Vol 48 No 3 (2025)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v48i3.1806

Abstract

The Sumatran back-arc basins developed beginning in the Middle Eocene, characterized by a variety of graben alignment patterns, which serve as critical indicators in understanding their formation history. One such basin is the North Sumatra Basin, dominated by north-south-trending grabens. These grabens are best observed in the Gurami-Tamiang Area. This research focuses on the subsurface analysis of this area, specifically: (i) detailed seismic interpretation of four east-west cross-sections that span several grabens, and (ii) palinspastic reconstructions to investigate structural and strain evolution over time, and its tectonochronostratigraphic chart. Generally, the structural configuration of the Gurami-Tamiang Area is defined by half-grabens bounded by east-dipping faults originating from negative flower structures at depth. The results show three phases of evolution: (i) Extensional Phase (45 - 32 Ma) is characterized by growth strata and strain magnitudes of (+) 4.2% to (+) 11.64%, (ii) Transitional Phase (32 - 22 Ma) is displaying both positive and negative strains of (+) 2.3% to (-) 1.7%,  with growth strata that are extending across grabens; and (iii) Contractional Phase (22 Ma – present) is characterized by negative strains of (-) 0.92% toward zero and mostly covered by post-extensional and syn-inversion deposits. The evolutionary phases indicate a novelty in the area, with the graben formation being part of a wrench fault system that includes the Khlong-Marui Fault, the Lokop-Kutacane Fault, and the Sumatra Fault.
A Techno-Economic Approach to Optimizing CCS Fiscal Parameters in Indonesia: A Case Study of Integrated Oil and Gas Development in CO2-Rich Areas Najeela Faza Ramadhani; Dedy Irawan; Sudono; Prasandi Abdul Aziz
Scientific Contributions Oil and Gas Vol 48 No 3 (2025)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v48i3.1809

Abstract

This study introduces a techno-economic approach to optimizing storage fees for CCS integrated with oil and gas development. The analysis adopts the production sharing contract cost recovery model in accordance with the implementation of Ministerial Regulation of Energy and Mineral Resources No. 16 of 2024, which addresses CCS-related parameters. Technical assessment confirms the studied reservoir’s suitability for long-term CO₂ injection through 5 injection wells, while oil and gas development are supported by 10 oil wells and 8 gas wells. The project’s economic viability under baseline conditions shows an IRR of 10.14% and POT of 15.73 years. Sensitivity analysis across fiscal parameters, such as investment credit, FTP, contractor split, CCS service fee and storage fee, CAPEX, royalty, and tax, identifies the storage fee as the most influential factor for viability. To achieve a commercially viable IRR of 15%, the project requires a minimum CCS service fee of 55 US$/MT and a storage fee of at least 35 US$/MT. The study underscores the need for clear regulations on fiscal incentives, CO₂ pricing, storage fees, and PSC integration to enhance CCS economic viability, while also offering a replicable framework for CO₂ assessments under dynamic fiscal regimes.
Performance Evaluation of Tween 60 Surfactant for EOR: Interfacial Tension Reduction and Microemulsion Formation Pauhesti Pauhesti; Ridha Husla; Sri Feni Maulindani; Apriandi Rizkina Rangga Wastu; Nadira Cahya Sutikna; Lailatul Wastiyah; Ade Kurniawan Saputra
Scientific Contributions Oil and Gas Vol 48 No 3 (2025)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v48i3.1812

Abstract

Enhanced Oil Recovery (EOR) techniques are essential for maximizing crude oil extraction from mature reservoirs. Surfactant injection, particularly using surfactants such as Tween 60, has shown great potential in reducing interfacial tension (IFT) and enhancing oil recovery. This study evaluates the performance of Tween 60 for EOR applications, focusing on its aqueous stability, phase behavior, IFT reduction, and core flooding efficiency at temperatures of 60°C and 80°C. The research addresses a gap in the literature by examining the long-term stability and phase behavior of Tween 60 at these temperatures. Aqueous stability tests over seven days indicate that Tween 60 remains clear and stable at 60°C but becomes cloudy and unstable at 80°C. Phase behavior tests reveal that a 0.5% concentration of Tween 60 produces the largest middle-phase microemulsion (5.75% volume), forming a bicontinuous Winsor III microemulsion that enhances oil-water interaction. IF T tests using a spinning drop tensiometer show a reduction in IFT to 0.00525 dyne/cm. Core flooding tests confirm that surfactant injection contributes an incremental oil recovery of 8.33% beyond what was achieved by waterflooding without surfactant, increasing the total recovery factor from 62.5% to 70.83%. However, limitations such as the short testing period (14 days) and the use of a single type of oil (39 ° API) underscore the need for further research.
Performance of Lignoslfonate Derived from Coffee Husk as A Natural Emulsifier in Enhanced Oil Recovery: A Phase Behaviour Study Luthfi Rindra Salam Rindra Salam; Riska Laksmita Sari; Welayaturromadhona
Scientific Contributions Oil and Gas Vol 48 No 3 (2025)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v48i3.1822

Abstract

The oil industry faces challenges in enhancing oil recovery while reducing environmental impact. This study explores the utilization of lignin extracted from coffee husk, an agricultural waste, as a natural emulsifier in enhanced oil recovery (EOR). The research addresses key issues including identifying lignin's functional groups via fourier transform infrared (FTIR) spectroscopy before and after sulfonation, determining compatible lignosulfonate concentrations through aqueous stability tests, and optimizing salinity for effective emulsification. Lignin was extracted via soda pulping and modified through sulfonation with sodium bisulfite (NaHSO₃) to produce lignosulfonate. FTIR analysis confirmed successful sulfonation, evidenced by new peaks at 636 cm⁻¹ (S–O) and 1101 cm⁻¹ (SO₃⁻). Aqueous stability tests at 60°C showed that a 0.8% (w/v) lignosulfonate concentration remained stable in brine with 20,000 ppm salinity. Salinity scans identified optimal conditions at 25,000 ppm, where the system achieved a balanced solubilization ratio of 0.95, indicating low interfacial tension. These results demonstrate that sulfonated coffee husk lignin has significant potential as a sustainable emulsifier for EOR applications, with a concentration of 0.8% and a salinity of 25,000 ppm being optimal for emulsion stability. This study supports circular economy principles by valorizing agricultural waste and offers a promising alternative to synthetic chemicals in the oil industry.

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