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Muhammad Taufiq Fathaddin
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Program Studi Magister Teknik Perminyakan (Master of Petroleum Engineering) Fakultas Teknologi Kebumian dan Energi Universitas Trisakti Gedung D Lantai 5 Universitas Trisakti, Jalan Kyai Tapa No.1 Grogol, Jakarta Barat, 11440, Indonesia.
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Journal of Earth Energy Science, Engineering, and Technology
Published by Universitas Trisakti
ISSN : 26153653     EISSN : 26140268     DOI : https://doi.org/10.25105/jeeset.v1i1
Core Subject : Science,
Energy
This journal intends to be of interest and utility to researchers and practitioners in the academic, industrial, and governmental institutions.
Arjuna Subject : Energi (semua kategori) - Energi Terbarukan, Keberlanjutan dan Lingkungan
Articles 133 Documents
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Modeling and Prediction of Kappaphycus alvarezii Viscosity Using Artificial Neural Network and Adaptive Neuro-Fuzzy Inference System Fathaddin, Muhammad Taufiq; Ridaliani, Onnie; Rakhmanto, Pri Agung; Mardiana, Dwi Atty; Septianingrum, Wydhea Ayu; Irawan, Sonny; Abdillah, Ridho
Journal of Earth Energy Science, Engineering, and Technology Vol. 8 No. 3 (2025): JEESET VOL. 8 NO. 3 2025
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/fh90e382

Abstract

This study examines the viscosity behavior of Kappaphycus alvarezii polymer solutions enhanced with TiO2 nanoparticles under varying concentrations, salinity, and temperature. Predictive models were developed using Artificial Neural Network (ANN) and Adaptive Neuro-Fuzzy Inference System (ANFIS) approaches. The experimental work involved preparing Kappaphycus alvarezii solutions with polymer concentrations ranging from 2,000 to 6,000 ppm and TiO2 nanoparticle concentrations from 2,000 to 4,000 ppm at salinities of 6,000–30,000 ppm and temperatures between 30 °C and 80 °C. Results showed that increasing Kappaphycus alvarezii concentration enhanced viscosity by 1.04–21.12%, while TiO2 nanoparticles improved viscosity stability, especially under high-salinity conditions. In contrast, higher salinity and temperature reduced viscosity due to ionic screening and increased molecular motion, although a slight rise was observed at 30,000 ppm salinity. The optimized ANN model (18 neurons, one hidden layer) achieved a superior correlation coefficient (r = 0.9980) compared to ANFIS (r = 0.8769), confirming higher predictive accuracy. These findings demonstrate the potential of Kappaphycus alvarezii–TiO2 nanofluids as sustainable viscosity modifiers for enhanced oil recovery (EOR) and verify the reliability of ANN and ANFIS models in predicting viscosity under complex multivariable interactions.
The Effect of Temperature on Filtration Loss and Mud Cake on The Concentration of Corn Starch Using the KCl-Polymer Sludge System fira, Safira Azzahra; Lestari; Samura, Lisa; Nugrahanti, Asri; Kartini, Rachmi
Journal of Earth Energy Science, Engineering, and Technology Vol. 6 No. 2 (2023): JEESET VOL. 6 NO. 2 2023
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/jeeset.v6i2.17685

Abstract

Drilling mud is a type of fluid that can help smoothing a drilling. The function of the drilling mud in the drilling process is to lift the drilling cutting. In this laboratory research, corn starch was used as a substitute for starch to reduce filtration loss. Corn starch is made by cleaning, drying, grinding, and sieving. The purpose of this research is to make mud with the addition of corn starch. its effect on filtration loss and mud cake at two temperature conditions. In this study the use of corn starch to be mixed into the mud with concentrations of 3 grams, 5 grams, 7 grams, 9 grams, and 11 grams. Accordingly, it can be seen which mud composition complies with the standard drilling mud specifications. Laboratory test results showed that the addition of corn starch additives caused a decrease in filtration loss for each difference in concentration and temperature. With the addition of 11 grams of corn starch, filtration loss decreased from 6.2 ml to 4.4 ml at 80°F, and it decreased from 5.2 ml to 3.9 ml at 200°F. In addition, corn starch additives cause the thickness of the mud cake formed to decrease. At a temperature of 80 oF the thickness of the mud cake decreased from 0.76 mm to 0.46 mm, while at a temperature of 200 oF it decreased from 0.62 to 0.42 mm. Based on the research results, corn starch additives and temperature influence changes in filtration loss and mud cake.
Optimization of Hydraulic Fracturing Modeling on The Proppant Flowback Issue Well DF-007 Nugraha, Fanata Yudha; Cahyaningtyas, Ndaru; Addin, Dhaffa Izuddin; Tony, Brian; Nandiwardhana, Damar
Journal of Earth Energy Science, Engineering, and Technology Vol. 8 No. 3 (2025): JEESET VOL. 8 NO. 3 2025
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/dkvxbf52

Abstract

Well DF-007, Field IA, Talang Akar Formation has low permeability that hinders well productivity. To improve production performance, hydraulic fracturing operations need to be conducted on the well. However, after the operation, a proppant flowback problem was discovered when the well was put back into production. This issue disrupts production performance and causes proppant accumulation. This problem indicates the need for a comprehensive analysis of the factors leading to proppant flowback issues, before determining a solution that addresses the root cause of the problem. The research flow begins with analyzing the factors causing proppant flowback issues such as initial production management settings, mechanical, and hydrodynamic force factors. After identifying the main issue, which is the hydrodynamic force factor, the process continues to the re-modeling stage by selecting proppants and fracturing fluids. The solution is determined by selecting the YF135.1HTD fracturing fluid with high viscosity to optimize proppant transportation, as well as choosing a combination of conventional proppants and adding resin-coated or rod-shaped proppants in the final stage to strengthen the stability of the proppant layer. The evaluation results show that the use of a combination of the fracturing fluid YF135.1HTD and the proppants BorProp 16/20 (Ceramic) + 16/20 XRT Ceramax I (Resin Coated Ceramic) can increase the average formation permeability from 5.33 mD to 181 mD, skin factor from +11.65 (damaged) to -6.03 (stimulated), fold of increase (FOI) of 8.21 times, as well as an increase in the gross rate on the inflow performance relationship (IPR) from previously 88 BFPD to 880 BFPD.
Salinity Effects on Anionic AEC Surfactant with Crude Oil: IFT, Phase Behavior, Solubilization, Microemulsion Viscosity Swadesi, Boni; Azmia, Fadhlan Barrul; Pratiknyo, Avianto Kabul; Kurniawan, Aditya; Suwardi
Journal of Earth Energy Science, Engineering, and Technology Vol. 8 No. 3 (2025): JEESET VOL. 8 NO. 3 2025
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/tqms0g23

Abstract

The investigates the influence of NaCl salinity (0–32,000 ppm) on the performance of Alkyl Ethoxy Carboxylate (AEC) anionic surfactants for Enhanced Oil Recovery (EOR), using light crude oil as a model. Salinity fundamentally affects the system's Interfacial Tension (IFT), phase behavior, solubilization, and microemulsion rheology. The objectives were to map these effects and determine the optimal operational salinity and surfactant working concentration. The working concentration of 1.75% w/w was established above the Critical Micelle Concentration (CMC), determined from the breakpoint of the IFT curve versus log AEC concentration. IFT was precisely measured using a spinning-drop tensiometer. Phase behavior was characterized via a salinity scan to map the Winsor I–III–II transition, and the solubilization ratio was calculated from the equilibrium volume of the middle phase. Microemulsion viscosity was measured using a Brookfield DV3T viscometer with a stepwise shear protocol. The key results showed that an optimum salinity window produced ultra-low IFT, led to the formation of Winsor III microemulsions with a balanced oil/water solubilization ratio, and caused a viscosity peak that coincided with the Hydrophilic-Lipophilic Difference (HLD) ≈ 0 conditions. The microemulsions exhibited characteristic shear-thinning behavior across the tested shear rates. Salinity systematically controls the key physicochemical properties of the AEC–crude oil system. The findings provide: selecting the working concentration based on the CMC test and choosing the salinity at HLD ≈ 0 maximize residual oil mobilization while minimizing phase instability risks. Operational implications include precise brine selection, surfactant dosage control, and adaptive staged slug injection strategies.
Geomechanical Characterisation Analysis of Reservoirs Based on Well Logging Data for CO₂ Injection Applications Rusmaladewi, Fitri; Louhenapessy, Stevy; Hendrawan, Rezki Naufan; Kurnia, Dwi Miftha; Kurniawan, Randy Yusuf
Journal of Earth Energy Science, Engineering, and Technology Vol. 8 No. 3 (2025): JEESET VOL. 8 NO. 3 2025
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/7dve7558

Abstract

This study investigates reservoir geomechanical characterization for CO₂ injection applications in the Akimeugah Basin using well-logging and 2D seismic data as the basis for constructing a one-dimensional Mechanical Earth Model (MEM) for well FRD2. The main log data used include sonic logs (Vp, Vs), density, and other logs to calculate dynamic elastic parameters, rock strength (UCS, tensile strength), pore pressure, and in-situ stress profiles (Sv, SHmax, Shmin), which are then validated by horizon and fault interpretation from seismic sections. Analysis of stress polygons, stress profiles, and stereonet plots at depths of 3100–4000 ft indicates that the stress regime is dominated by Normal Faulting with a maximum horizontal stress direction (SHmax) of approximately 150°, with no indication of overpressure but with depth-dependent geomechanical sensitivity to changes in injection pressure. The evaluation results show that the deeper interval (around 4000 ft) exhibits higher rock strength, a wider safe pressure window, fracture gradients well above pore pressure, and narrower zones of potential failure, making it the most suitable and safest target for CO₂ injection, while the 3100–3500 ft interval remains prospective but requires stricter pressure control.
Drilling Efficiency Analysis Using Drilling Specific Energy Approach: A Comparative Study of Wells RM-01 and RM-02 Ghani, Muhammad Hafiyyan; Setiati, Rini; Sutresno, Wahyu; Caesar, Athifa Putri
Journal of Earth Energy Science, Engineering, and Technology Vol. 8 No. 3 (2025): JEESET VOL. 8 NO. 3 2025
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/aq71r372

Abstract

Drilling operations represent the largest cost component in geothermal field development, particularly when penetrating abrasive volcanic formations that often reduce drilling efficiency and Rate of Penetration (ROP). In the RM geothermal field, the 12¼-inch hole section encounters hard volcanic rocks that pose operational challenges. This study aims to evaluate drilling efficiency and compare performance between wells RM-01 and RM-02 using the Drilling Specific Energy (DSE) approach. A quantitative comparative method was applied using historical drilling data from RM-01 and real-time drilling parameter data from RM-02, including Weight on Bit (WOB), Rotary Speed (RPM), Torque, and Rate of Penetration (ROP). DSE values were calculated using Teale’s specific energy equation and analyzed to identify inefficient drilling zones and evaluate the impact of hydraulic optimization. The results indicate that efficient drilling conditions were achieved only at shallower depths (1200 m in RM-01 and 1500 m in RM-02), where DSE values were relatively low. Hydraulic optimization reduced the average DSE by approximately 43 psi (0.18%) in RM-01 and 510 psi (1.01%) in RM-02, indicating improved drilling efficiency. However, DSE values at deeper intervals remained high, suggesting that formation strength and abrasiveness significantly affect drilling performance. The study is limited by the use of a limited number of wells and the focus primarily on hydraulic optimization without extensive analysis of other mechanical parameters such as bit design, vibration control, and broader lithological variability. Further research incorporating additional wells and integrated mechanical-hydraulic optimization is recommended to achieve more substantial improvements in drilling efficiency.
Effectiveness of MES Palm Oil Surfactant using Core Flooding and Spontaneous Imbibition in EOR methods Setiati, Rini; Haryono, Muhammad Furqon; Ristawati, Arinda; Samsol; Akbar, Fahrurrozi; Bharoto; Sumirat, Iwan; Ramadhan, Ranggi Sahmura
Journal of Earth Energy Science, Engineering, and Technology Vol. 9 No. 1 (2026): JEESET VOL. 9 NO. 1 2026
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/mvpkat05

Abstract

Enhanced Oil Recovery (EOR) is one of the methods developed to optimize oil extraction from wells that still have reserve potential. This study focuses on the application of surfactant injection techniques using vegetable-based surfactants derived from Methil Ester Sulfonate (MES) from palm oil. The objective of this study is to evaluate the effectiveness of MES surfactants in increasing the recovery factor through two main testing methods, namely core flooding test and spontaneous imbibition. The tests were conducted under two variations of conditions, namely salinity of 5,000 ppm at a concentration of 0.5% and salinity of 10,000 ppm at a concentration of 2%. The test results showed that in the core flooding method, a salinity of 5,000 ppm with a concentration of 0.5% produced the highest recovery factor of 84.74%, while a salinity of 10,000 ppm with a concentration of 2% produced 62.63%. Meanwhile, in spontaneous imbibition testing, the recovery factor achieved was 51.94% for a concentration of 0.5% and 45.24% for a concentration of 2%. Based on these results, it can be concluded that the most optimal conditions for increasing oil recovery with palm oil MES surfactant are achieved in the core flooding test method with a salinity of 5,000 ppm and a concentration of 0.5%..
Characteristics and Performance of Xanthan Gum–Kappaphycus alvarezii Mixture for Increasing Oil Recovery in Reservoirs with High Salinity Septianingrum, Wydhea Ayu; Abdillah, Ridho; Iqlimah, Madhu A’la Zulaiqoh; Fathaddin, Muhammad Taufiq; Husla, Ridha; Insani, Andon; Kartini, Rachmi; Andrianaivo, Lala
Journal of Earth Energy Science, Engineering, and Technology Vol. 9 No. 2 (2026): JEESET VOL. 9 NO. 2 2026
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/n9b8cy58

Abstract

Polymer flooding is an effective Enhanced Oil Recovery (EOR) method; however, challenges arise in reservoir conditions with high salinity and temperature, which can degrade conventional polymers. This study aims to analyze the rheological characteristics and sweeping performance of a polymer mixture consisting of Xanthan Gum (XG) and a natural additive from red seaweed, Kappaphycus alvarezii (KA). The research methodology includes viscosity testing against variations in temperature and salinity (30,000–50,000 ppm), contact angle measurements for wettability evaluation, adsorption tests in porous media, and coreflooding experiments. The novelty of this research lies in the utilization of Kappaphycus alvarezii as a natural performance-enhancing agent for XG capable of significantly improving fluid-rock interactions. The results indicate that the addition of KA provides a synergistic effect in increasing solution viscosity and stability. Contact angle measurements prove that KA is much more effective in altering rock wettability to water-wet with a value of 29°, compared to XG at 87°, thus being more optimal in releasing oil from rock pores. Adsorption tests showed an increase in polymer retention as salinity rose, yet remained within operational tolerance. In the coreflooding stage, a 12,000ppm solution at 30,000 ppm salinity yielded the highest incremental recovery factor of 13.33%. Overall, the study concludes that the XG-KA mixture has high potential for application in high-salinity reservoirs due to its superiority in mobility control and wettability modification compared to the use of single polymers.
Comparative Analysis of Water Injection Patterns and Rates for Oil Recovery Optimization in a Mature Reservoir Wibowo, Djunaedi Agus; Rahmawan, Sigit; Sabirey, Adrian Maulana; Andrianaivo, Lala
Journal of Earth Energy Science, Engineering, and Technology Vol. 9 No. 1 (2026): JEESET VOL. 9 NO. 1 2026
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/1t7py069

Abstract

Waterflooding is one of the most widely applied secondary recovery methods to maintain reservoir pressure and improve oil recovery in mature oil fields. However, ineffective injection patterns and non-optimal injection rates may reduce sweep efficiency and accelerate water breakthrough. Therefore, this study aims to evaluate and optimize waterflood injection patterns and injection rates in Layer Y of Field X using dynamic reservoir simulation with tNavigator. The study employed a full-field black-oil simulation model involving data preparation, model initialization, history matching, and production forecasting under several development scenarios. The evaluated scenarios included base case, infill drilling, and water injection using 3-spot, 5-spot, and 7-spot injection patterns with different injection rates. This study applied the integration of comparative injection-pattern analysis with injection-rate optimization using a validated full-field simulation model for a mature reservoir. The initialization and history matching results showed good agreement between the simulation model and historical field data, indicating that the model was reliable for forecasting purposes. The simulation results demonstrate that waterflood implementation significantly improved reservoir performance compared with the base case and infill drilling scenarios. Among all evaluated cases, the 5-spot injection pattern with an injection rate of 1000 STB/day produced the best performance, achieving a cumulative oil production of 97.36 MMSTB and a recovery factor of 46.76%. The study confirms that optimizing injection pattern geometry and injection rate plays an important role in improving sweep efficiency and maximizing oil recovery in mature reservoirs.
Development of Inflow Performance Relationship Equations Based on The Vogel and Eickmeier Methods Napitupulu, Welman Daud; Destarandra, Octa Rifallah; Louhenapessy, Stevy C.; Manurung, Wulan Indah Syari; Khadaffilam, Muhammad Rizqidina; Wicaksono, Abieza Septiawan
Journal of Earth Energy Science, Engineering, and Technology Vol. 9 No. 1 (2026): JEESET VOL. 9 NO. 1 2026
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/vd8hf144

Abstract

The conventional Vogel Inflow Performance Relationship (IPR) method, when applied to oil wells, exhibits substantial discrepancies relative to actual production data. Consequently, the Development of a more representative model is imperative to enhance the precision of well performance predictions. The objective of this study is to develop an IPR equation based on the Vogel and Eickmeier methods that better aligns with the characteristics of the reservoir under study. Accurate IPR evaluation is imperative for predicting oil production rates in response to variations in well bottomhole pressure, thereby supporting decision-making in production planning, flow-rate optimization, and field-development feasibility studies. The analysis results indicate that developing an IPR equation based on the Vogel and Eickmeier methods can reduce forecasting errors and accurately represent the relationship between oil production rates and well bottom pressure. Consequently, the developed IPR model can serve as a tool to aid in production management and further Development planning.

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