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All Journal Seminar Nasional Teknik Kimia Kejuangan Journal of Engineering and Technological Sciences Techno LPPM Journal of Geoscience, Engineering, Environment, and Technology JOURNAL OF EARTH ENERGY ENGINEERING Journal of Petroleum and Geothermal Technology Petro : Jurnal Ilmiah Teknik Perminyakan Journal of Earth Energy Science, Engineering, and Technology Scientific Contributions Oil and Gas
Boni Swadesi
Department Of Petroleum Engineering, Faculty Of Mineral Technology, Universitas Pembangunan Nasional “Veteran” Yogyakarta, Indonesia
Biochemistry, Genetics & Molecular Biology Chemical Engineering, Chemistry & Bioengineering Earth & Planetary Sciences Economics, Econometrics & Finance Energy Engineering Environmental Science Materials Science & Nanotechnology Physics

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Evaluation of The Use of Diptube and Cyclone on The HPU Pump Downhole to Address The Sand Problem and Gas Interference in The ARD-22 Pangkalan Susu Field Widodo, Aris; Suranto, Suranto; Swadesi, Boni; Ratnaningsih, Dyah Rini; Kristanto, Dedy; Ridha, Syahrir
Journal of Petroleum and Geothermal Technology Vol. 5 No. 2 (2024): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v5i2.12349

Abstract

The problem of sand and gas interference in artificial lift pumps is a serious problem. The ARD-22 well in Pangkalan Susu often goes offline due to sand and gas interference. Solutions to overcome sand problems by reducing drag force and mechanical methods. Reducing drag force by setting the well production rate below or equal to the critical sand flow rate. The mechanical method is carried out by adjusting the flow pattern on the artificial lift and also by adding a downhole tool in the form of a Cyclone, which functions to make the fluid flow from the reservoir turbulent so as to separate solid particles from liquid. Another dominant problem with this well is the rising GOR or gas interference which causes gas lock problems, so it is necessary to redesign the diptube as a separation area between gas particles and liquid fluid. The monitoring results from this research showed that the fluid flow from the sampling point showed that there was no intermittent gas and the dynagraph readings also showed normal results. Optimum production can be recovered according to the initial potential of G/N 50/45, production lifetime increased after installation diptube cyclone to reach 7 more months and increased company revenues totaled Rp. 8.306.660,000.
OIL RESERVES ANALYSIS IN BATANG FIELD WITH MATERIAL BALANCE METHOD FOR PRESSURE MAINTENANCE Winant, Fachri Muhammad; Suranto, Suranto; Swadesi, Boni
Journal TECHNO Vol. 7 No. 1 (2021): Mei
Publisher : Universitas Pembangunan Nasional Veteran Yogayakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/journal techno.v7i1.5287

Abstract

Material Balance method is a concept of material equilibrium with measurement of response from reservoir (pressure) due to production, injection, and influx activities so that it can calculate the appropriate Original Oil in Place. By creating a material balance model, it can be done the development plan of Batang Field with the aim of obtaining cumulative optimum oil production. Batang Field is still feasible to be developed using pressure maintenance scenarios seen from OOIP of 144.3 MMSTB, Recovery Factor of 14.9% and Current Pressure of 70-80 psi.  Pressure Maintenance is a water injection with the aim of replacing the fluid that has been produced so that it is expected to keep the reservoir pressure from falling. Ideally this method requires Voidage Replacement Ratio (VRR) = 1 as the target injection. Economic calculation using Cost Recovery from this scenario shows a positive NVP ($ 2,865,000 USD). Therefore, development projects using Pressure Maintenance can be applied in the field. With this paper, it is hoped that it can increase reserves and  lifespan of the Batang oil field.
Evaluation of the Viscosity of Terrafloc Polymer and Xanthan Gum Polymer Amri, Sulthoni; Setiati, Rini; Fathaddin, Muhammad Taufiq; Rakhmanto, Priagung; Swadesi, Boni; Ratnaningsih, Dyah Rini
Journal of Earth Energy Science, Engineering, and Technology Vol. 7 No. 1 (2024): JEESET VOL. 7 NO. 1 2024
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/jeeset.v7i1.17309

Abstract

Polymer injection is one of the EOR methods using chemical which is injected into the reservoir to increase oil recovery. The polymer functions to maintain the flow of fluids, especially water, so that it does not boil ahead of oil towards production wells. This is due to the ability of the polymer to increase the viscosity of the fluid in the reservoir. The polymers commonly used in the petroleum world are synthetic polymers and natural polymers which are often referred to as biopolymers. The type of biopolymer in this article is Xanthan Gum while the synthetic polymer used is Terrafloc. The characteristics of these two polymers are compared so that the performance that will be obtained in an effort to increase the recovery of petroleum can be estimated. From the results of the viscosity measurement, it turned out that the Xanthan Gum polymer had a much greater viscosity value than the Terrafloc polymer. Thus, the use of Xanthan Gum and Terrafloc polymers can be adjusted to the needs related to the type of crude oil in the reservoir to be injected so that the results of obtaining petroleum can be optimal.
Analysis Of Co2 Storage in A Saline Aquifer Using A Fully Implicit Integrated Network Modeling Approach in the 'AZ' Field Swadesi, Boni; Zayd, Ahmad; Buntoro, Aris; Kristanto, Dedi; Widiyaningsih, Indah; Lukmana, Allen Haryanto
Journal of Geoscience, Engineering, Environment, and Technology Vol. 10 No. 4 (2025): JGEET Vol 10 No 04 : December (2025)
Publisher : UIR PRESS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25299/jgeet.2025.10.4.25106

Abstract

The increasing carbon dioxide (CO2) emissions from industrial and energy activities have driven the development of Carbon Capture and Storage (CCS) technology as a key solution for climate change mitigation. Among various geological storage options, saline aquifers offer significant advantages due to their large storage capacity, wide distribution, independence from hydrocarbon value, and stable geological and geochemical conditions. The “AZ” Field, located near a power plant emitting 2.2 million tons of CO2 annually, was selected as the study site for CO2 storage. This study aims to analyze the trapping mechanisms and optimize the CO2 storage capacity (storativity) using a fully implicit integrated modeling approach. The methodology involves building a static and dynamic model of the Johansen Formation saline aquifer, and integrating well and surface facility models using the well designer and network designer features in tNavigator. A 140-year simulation was conducted, comprising 40 years of injection and 100 years of post-injection period. Simulation results show that the “AZ” Field can store up to 83.9 Mt of CO2, predominantly through solubility/residual trapping mechanisms, in addition to structural trapping. No leakage was observed to the surface, indicating that caprock integrity remained intact throughout the simulation period. The fully implicit integrated modeling approach effectively captured the dynamic interactions between the reservoir, wells, and surface facilities, supporting the feasibility of the “AZ” Field as a safe and sustainable CO2 storage site.
OPTIMASI INJEKSI BIOSURFAKTAN PADA PENINGKATAN PEROLEHAN MINYAK MELALUI SIMULASI CORE FLOODING Ferdinandus, Evan Raymond; Swadesi, Boni; Kololu, Micky
Petro : Jurnal Ilmiah Teknik Perminyakan Vol. 14 No. 4 (2025): Desember 2025
Publisher : Jurusan Teknik Perminyakan Fakultas Teknologi Kebumian dan Energi Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/petro.v14i4.24096

Abstract

Peningkatan perolehan minyak (EOR) merupakan teknologi penting untuk memaksimalkan produksi dari reservoir yang telah mengalami penurunan laju produksi. Salah satu metode EOR yang berkembang adalah penggunaan biosurfaktan, yang dinilai lebih ramah lingkungan dibanding surfaktan sintetis. Penelitian ini bertujuan menentukan skenario paling optimum penggunaan biosurfaktan rhamnolipids untuk meningkatkan perolehan minyak melalui simulasi core flooding skala laboratorium. Simulasi dilakukan menggunakan CMG STARS pada model kartesian 3D batu pasir Berea dengan variasi parameter utama, yaitu konsentrasi biosurfaktan, laju injeksi, dan urutan injeksi slug. Rhamnolipids mampu menurunkan tegangan antarmuka minyak-air, sehingga meningkatkan efisiensi perpindahan minyak dari pori-pori batuan. Hasil simulasi menunjukkan bahwa konsentrasi optimum adalah 14 %b/b dengan faktor perolehan (RF) tertinggi sebesar 40.15 %. Laju injeksi optimum ditemukan pada 1 cm³/menit, menghasilkan RF 48.53 % dalam rentang laju yang memungkinkan untuk uji core flooding laboratorium. Untuk skenario injeksi berulang air dan biosurfaktan, hasil terbaik diperoleh pada pola injeksi yang diawali dengan air, diikuti biosurfaktan, lalu diulang sekali lagi (W-B-W-B), dengan RF tertinggi 51.25 %. Temuan ini memberikan acuan penting untuk desain injeksi biosurfaktan pada tahap percontohan skala lapangan.
Chemical Enhanced Oil Recovery (CEOR) Injection Planning to Obtain the Optimum Development Scenario: A Case Study in TBG Field Aliefan, Tubagus Adam; Kristanto, Dedi; Swadesi, Boni
Journal of Petroleum and Geothermal Technology Vol. 6 No. 2 (2025): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v6i2.14218

Abstract

Chemical Enhanced Oil Recovery (CEOR), particularly through the use of surfactant and polymer injection, has emerged as one of the most effective tertiary recovery techniques for increasing oil recovery from mature reservoirs. CEOR enhances volumetric and microscopic sweeping efficiency, improving the overall recovery factor (RF). This study focuses on Zone C of the TBG Field, a mature oil field with a current recovery factor below 25%, highlighting its potential for further optimization through CEOR. The field, which began production in 1961 and introduced peripheral water injection in 1995, remains a key candidate for unlocking remaining oil in place. This research integrates primary data, including core analysis, PVT data, and polymer field trial results, with secondary data such as petrophysical properties and production performance. Using dynamic modeling with CMG software, the study evaluates three CEOR injection scenarios to determine the most effective method for improving oil recovery. The scenarios simulated included Baseline Waterflood + Polymer (0.4 PV) and Baseline Waterflood + (Surfactant + Polymer) + (Polymer) (0.2 PV SP + 0.7 PV P). The optimal scenario, involving Baseline Waterflood + (Surfactant + Polymer) + (Polymer), demonstrated an incremental oil recovery of 1.24 MMSTB and a recovery factor improvement of 0.974%. The novelty of this research lies in its integration of polymer field trial data with innovative surfactant-polymer combinations tailored specifically to Zone C's reservoir characteristics. This approach provides a scientifically robust and practical strategy for enhancing oil recovery in challenging reservoir conditions. The study concludes that CEOR is a viable method for mature fields like TBG, offering significant potential for improved oil recovery. Future recommendations include exploring the economic feasibility of the selected injection scenario and ensuring the readiness of surface facilities to support full-scale implementation.
Evaluation of Drill Bits Use in KRS-09 Well, Kuarsa Field Based on Well Log Data, XRD Testing and MBT From Drill Cuttings Alfatah, Faritsi Luqman; Buntoro, Aris; Swadesi, Boni; Hartoyo, Puji; Putradianto, Ristiyan Ragil
Journal of Petroleum and Geothermal Technology Vol. 6 No. 2 (2025): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v6i2.14876

Abstract

The use of drill bits in well drilling is very important to break and penetrate rocks. The selection of drill bits is usually done by testing drill bits from previous wells that have similar static rock mechanical parameters, but this method is time consuming and expensive because the core must be analyzed in the laboratory. As an alternative, the selection of drill bits is evaluated using logging data as an approach to calculating the Unconfined Compressive Strength (UCS) value whose accuracy is improved by integrated the brittleness index through X-Ray Diffraction (XRD) analysis and Mechanical Specific Energy (MSE) parameter to assess how efficiently drilling is performed. The obtained parameter data is then calculated for correlation using Pearson correlation. Integration of rock mechanical (UCS, BI, MSE) and mineralogy has proven to be more effective in selecting drill bits than experience-based methods. Therefore, drilling planning should consider rock strength, deformation properties, and mineral composition to improve drill bit efficiency and life.
Waterflood and Polymer Injection Design for New Target Reservoir based on Injection Pattern Optimization, Injection Rate Sensitivity, and Injection Pressure Sensitivity Fransiscus Asisi Lugas Ariobimo; Swadesi, Boni; Suhascaryo, Nur
Journal of Petroleum and Geothermal Technology Vol. 6 No. 2 (2025): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v6i2.16337

Abstract

Field “X” is in Tabalong Regency, South Kalimantan, and is operated by Pertamina Hulu Indonesia Zona 9. The peak primary production occurred in March 1963, reaching 47,963 BOPD. Full-scale waterflood implementation with a staggered line-drive injection pattern began in January 1995, and the peak secondary production occurred in January 1999 at 10,095 BOPD. This study was conducted using a dynamic model that had undergone initialization validation and history matching. The assessment of polymer injection pattern candidates was carried out through a screening stage based on screening criteria and reservoir property analysis to determine patterns that could be prioritized as pilot areas for an optimal polymer injection scenario in Zone B. Pattern analysis criteria were based on movable remaining oil saturation, movable remaining oil in place, pattern area, and average transmissibility, evaluated for the Zone B reservoir under post-waterflood conditions. Sensitivity analyses on water injection rate and injection pressure were then performed to obtain the optimum waterflood injection scenario. After optimizing the injection pattern and determining the optimum waterflood injection scenario, polymer input parameters were applied to the model, followed by sensitivity analyses on polymer injection rate and pressure to obtain the optimum polymer injection scenario for Zone “B” of Field “X By the end of the production forecast in January 2066, the optimum waterflood injection scenario at the end of the production forecast provides an incremental oil gain of 1.5 MMSTB with an incremental recovery factor of 2.19% relative to OOIP, while the combination of optimum waterflood and polymer injection at the end of the production forecast provides an incremental oil gain of 2.14 MMSTB with an incremental recovery factor of 3.13% relative to OOIP; demonstrating improved sweep efficiency, oil bank formation, and effective mobilization of residual oil across Zone B.
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.
Caprock Integrity Assessment from Core-Based Formation Analysis and Laboratory Workflow: A Case Study of The Asri Basin Caprock Buntoro, Aris; Putra, Teddy Eka; Kristanto, Dedi; Swadesi, Boni; Amir, Zulhemi; Lukmana, Allen Haryanto; Wicaksono, Dimas Suryo; Nurcholis, Muhammad
Scientific Contributions Oil and Gas Vol 49 No 1 (2026)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v49i1.2021

Abstract

Caprock integrity is a critical factor in ensuring the long-term safety of CO₂ geological storage, enhanced oil recovery (EOR), and wellbore stability. This study investigates the sealing performance of shale- and carbonate-rich caprock intervals from the Asri Basin, with specific focus on the Baturaja and Gita Formations. This study introduces a CT-guided integrated laboratory workflow for caprock integrity assessment, which simultaneously links petrophysical sealing capacity, mineralogical controls, and geomechanical strength within a unified experimental framework, a workflow rarely applied in Southeast Asian basins. Whole-core sections from Well ASR-1 were screened using computed tomography (CT) imaging to identify fractures and heterogeneity prior to plug extraction. Laboratory methods included porosity and permeability determination under variable confining stresses, mercury injection capillary pressure (MICP) analysis to evaluate sealing capacity, mineralogical characterization by X-ray diffraction (XRD), scanning electron microscopy (SEM–EDS), petrography, and mechanical testing (UCS, triaxial, and Brazilian tensile tests). The results demonstrate significant depth-dependent variability: The Baturaja Formation exhibited heterogeneous sealing capacity, with entry pressures ranging from 217 to 1,197 psi, while the Gita Formation consistently displayed strong sealing, with maximum Pc_entry of 2,844 psi and pore systems dominated by <0.1 µm throats. Mechanical tests confirmed adequate strength and the preservation of low permeability under confining stress, with clay content and carbonate cementation identified as primary controls on integrity. The integrated workflow enables a process-based interpretation of lithology-controlled sealing mechanisms, improving the robustness of site selection and risk assessment for CO₂ storage in the Asri Basin and similar carbonate and mudstone systems.
Co-Authors Aditya Kurniawan Ahmad Muraji Suranto Alfatah, Faritsi Luqman Aliefan, Tubagus Adam Amir, Zulhemi Amri, Sulthoni Aris Widodo Ayu Regita Pramesti Azmia, Fadhlan Barrul Buntoro, Aris Dedy Kristanto Deni Kurniawan Dyah Rini Ratnaningsih Fachri Muhammad Winant Fahrezi Oktaviandi Ferdinandus, Evan Raymond Fransiscus Asisi Lugas Ariobimo H.P. Septoratno Siregar H.P. Septoratno Siregar, H.P. Septoratno Hartoyo, Puji Indah Widiyaningsih Indah Widiyaningsih Indah Widiyaningsih Indah Widyaningsih Kololu, Micky Kristanto, Dedi Kristanto, Dedy KRT Nur Suhascaryo Leksono Mucharam Leksono Mucharam Lufis Alfian Alannafi lukmana, allen haryanto Matrida Jani Muhammad Taufiq Fathaddin, Muhammad Taufiq Nur Suhascaryo Nur Suhascaryo Nurcholis, Muhammad Pratiknyo, Avianto Kabul Putra, Teddy Eka Putradianto, Ristiyan Ragil Rakhmanto, Priagung Ratna Widyaningsih Ratna Widyaningsih Ratnaningsih, Dyah Rini Ridha, Syahrir Rini Setiati Roiduz Zumar Sinosa Husenido Sri Murni Sri Wahyu Murni Sri Wahyu Murni Suranto Suranto Suranto Suranto Suwardi Taufan Marhaendrajana, Taufan Wicaksono, Dimas Suryo Winant, Fachri Muhammad Zayd, Ahmad