cover
Article Per Year (5 Year)
All
Home Page
OAI Link
Editorial Team
Contact
Reviewer
Google Scholar
Contact Name
Wulandari
Contact Email
jurnal.lemigas@esdm.go.id
Phone
+6221-7394422
Journal Mail Official
jurnal.lemigas@esdm.go.id
Editorial Address
Jl. Ciledug Raya Kav. 109, Cipulir, Kebayoran Lama, Jakarta Selatan 12230
Location
Kota adm. jakarta selatan,
Dki jakarta
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 35 Documents
 1   2   3   4 
Search results for , issue "vol 49 no 3 (2026)" : 35 Documents clear
Effect of Corn Cob Addition on the Rheological and Filtration Properties of Water Based Drilling Mud Apriandi Rizkina Rangga Wastu; Ridha husla; Ghanima Yasmianiar; Asri Nugrahanti; Venezia Chelsea Reggiana Kalalo; R Hari Karyadi Oetomo; Siti Azizah
Scientific Contributions Oil and Gas Vol 49 No 3 (2026)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v49i3.2016

Abstract

Drilling mud is an essential tool in supporting the success of productive and economical oil and gas well drilling activities. Some chemical additives used to enhance the physical and rheological properties of mud tend to be toxic, non-biodegradable, and have negative environmental impacts. The use of household waste materials such as corn cobs, which can be reused as a natural polymer in drilling mud, presents a promising alternative. The separation of these materials serves the purpose of identifying a new type of polymer candidate, as they contain 41.27% cellulose, 46% hemicellulose, and 7.40% lignin, making them suitable for use as a polymer. The research involves analyzing the mud rheology, including plastic viscosity, yield point, gel strength, filtration loss, and mud cake, using three samples of water-based mud containing 1.5 grams, 3 grams, and 4.5 grams of finely ground corn cobs. The samples are then tested at two different temperatures, 80ºF and 200ºF, to observe the behavior of corn cobs when circulated into the well and entering formations with higher temperatures. Changes in rheological values and filtration loss with each additive addition will serve as indicators of the feasibility of corn cobs as a biodegradable alternative additive containing cellulose in drilling mud.
Optimizing CO₂ Storage in Saline Aquifers Through Pressure Redistribution in Natuna D-Alpha Field, Indonesia Roihan Arie Nirwana; Dedy Irawan; Amega Yasutra; Syarif Kamal; Welly Ahmad Ramadan
Scientific Contributions Oil and Gas Vol 49 No 3 (2026)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v49i3.2119

Abstract

The increasing concentration  of carbon dioxide (CO₂) in the atmosphere is significantly contributing to the critical exploration of Carbon Capture and Storage (CCS) technology. Although deep saline aquifers offer substantial storage potential for CO2, their effective capacity is often constrained by rapid formation pressure buildup near injector wells and poses safety risks. Therefore, this study aims to propose an integrated strategy to optimize CO₂ storage capacity using pressure redistribution method in a thick carbonate saline aquifer located in Natuna D-Alpha Field, Indonesia. A dynamic numerical simulation is developed by integrating 2D seismic, well logs, core analysis (RCAL/SCAL), and geomechanical parameters derived from log data. The effectiveness of lateral and vertical pressure redistribution is evaluated through brine production wells (PWs) and multi-depth injection, respectively, followed by perforation configuration optimization.Various scenarios are simulated to compare total gas injected and reservoir pressure response against rock fracture limits. The results showed that storage capacity is limited due to the absence of pressure management (Base Case). The implementation of lateral pressure redistribution through brine production proves to be the most significant strategy, capable of increasing storage capacity by approximately 64% of the Base Case in high-rate production scenarios. Furthermore, vertical redistribution strategy using multi-depth injection obtains a 13% capacity increase and improves vertical pressure distribution. A combination of multi-depth injection and brine production shows positive synergy, generating a 44% capacity increase with a storage efficiency of 0.58%. The results also indicate that variations in well perforation geometric patterns (line vs. cross) have minimal impact compared to global pressure management strategies. In line with the analysis, this study finds that brine extraction and vertical injection management are essential to maximizing safe CO₂ storage in thick aquifers.    
Full Tensor Gravity Gradiometry Sensitivity Analysis for Delineating Lateral Reservoir Boundaries and Subtle Density Contrasts Krisna Oka Mahendra; Muhammad Noor Amin Zakariah; Soni Satiawan; Boko Nurdiyanto Suwardi; Edy Widjanarko
Scientific Contributions Oil and Gas Vol 49 No 3 (2026)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v49i3.2116

Abstract

The gravity method is frequently used for regional basin mapping. However, this method has limitations in resolving rock layers at shallow targets or detecting subtle density contrasts between rock formations in oil and gas exploration. This study investigates the capability of Full Tensor Gravity (FTG) gradiometry to overcome these challenges in sedimentary basin delineation and shallow reservoir characterization. Forward numerical modeling was conducted using the SimPEG Python package to simulate a sedimentary basin containing a reservoir with varying thicknesses (100–500 meters) and rock density contrasts under different saturation conditions. Quantitative analysis demonstrates the superior sensitivity of FTG compared to conventional methods. For a 500-meter-thick gas-saturated reservoir, the horizontal FTG components (Gxx, Gyy) showed an anomaly magnitude change of 66.7%, and the vertical gradient (Gzz) exhibited an increase of 62.5%. These values are higher than the change in the conventional gravity anomaly (Gz), which only reached 52.0%. Furthermore, horizontal gradients effectively delineate the reservoir's lateral boundaries, while the vertical component provides a clearer representation of the overall basin structural geometry. This study confirms that FTG analysis yields a quantitatively improved subsurface model, thereby reducing the ambiguity associated with conventional gravity methods in delineating shallow prospects.
Rheological Screening of HPAM for High-Salinity EOR Esraa Osama; Adel M. Salem; Ahmed Alsabagh; Omar Elfarouk; Mahmoud Tantawy; Muhammad Saafan
Scientific Contributions Oil and Gas Vol 49 No 3 (2026)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v49i3.2125

Abstract

Hydrolyzed polyacrylamide (HPAM) polymer flooding is a practical chemical enhanced oil recovery method, but polymer performance can deteriorate under high salinity, elevated temperature, and high shear rate. This study presents an integrated laboratory screening workflow for five commercial HPAM polymers under reservoir-representative conditions. Polymer solutions were prepared at 500–5000 ppm and tested at shear rates of 1–1000 s⁻¹, salinities of 3,000–200,000 ppm, and temperatures up to 90 °C. Rheological screening was followed by adsorption and core flooding tests for the most suitable candidates, Polymers C and E. These two polymers were carried forward because they achieved the highest composite scores in the technical screening, combining strong viscosity retention with favorable injectivity and salinity/temperature tolerance. All polymers showed shear-thinning behavior, while salinity and temperature reduced apparent viscosity. Polymer A provided the highest bulk viscosity; however, Polymer C gave the best balance among viscosity retention, salinity tolerance, injectivity, adsorption behavior, and recovery performance. Core flooding confirmed that Polymer C at 3000 ppm produced the highest incremental recovery, approximately 10.0% in Core 1 and 8.8% in Core 2. The results show that HPAM selection should be based on integrated rheology, adsorption, and recovery testing rather than viscosity alone. The main contribution of this work to polymer technology is a transferable, six-stage integrated screening protocol that links rheological behavior, salinity and thermal tolerance, adsorption loss, and core-scale recovery response within a single laboratory workflow, providing a practical decision basis for selecting HPAM polymers for high-salinity EOR projects rather than relying on isolated viscosity or adsorption data.
Comparative Analysis of B35–B40 Biodiesel Blends in Passenger Train Generator Sets: Performance, Emissions, and 1,200 h Endurance Tests Riva Yudha Abriyant; Naufal Rasendriya Azmi; Irawan Adhi Putra; Faqih Supriyadi; Yogi Pramudito; Dimaz Warahadi; Riesta Anggarani; Eki Dwi Wijanarko; Cahyo Setyo Wibowo; Ahmad Syihan Auzani
Scientific Contributions Oil and Gas Vol 49 No 3 (2026)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v49i3.2129

Abstract

The transition from B35 to B40 biodiesel is a key step in reducing fossil diesel dependence in railway power systems, but its field performance in passenger train generator sets remains insufficiently established. This study evaluates comprehensively the fuel-lubricant quality, engine performance, fuel consumption, NOx emissions, rating component, and filter behaviour of B35 and B40 biodiesel blends in an MTU 10V1600G20F passenger train generator set. Initial tests compared B35 and B40 across different load conditions, followed by a 1,200 h dynamic endurance test using B40 during railway operation. As a results, B40 showed higher cetane number than B35 but lower heating value and higher water content, reflecting the expected trade-off of increasing FAME content. Despite this, B40 delivered power comparable to B35 at higher loads, while fuel consumption remained broadly similar under medium- and high-load operation. After 1,200 h, B40 maintained stable power output and fuel consumption, with no progressive increase in NOx emissions. All measured NOx values remained below the regulatory limit. Lubricant analysis, minor merit rating inspection, and Racor filter monitoring showed no severe oil degradation, abnormal component damage, or visible filter blockage. These findings indicate that B40 can be technically feasible for passenger train generator operation when supported by controlled fuel quality and routine maintenance.
Lithofacies Versus Well Identity as Controls on Fracture Porosity in Malay Basin Carbonates: A Two-Scale Statistical Decomposition Simeão Lourenco Correia da Silva; Muhammad Luqman Hasan; Dejen Teklu Asfha; Krisna Oka Mahendra
Scientific Contributions Oil and Gas Vol 49 No 3 (2026)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v49i3.2131

Abstract

Carbonate fracture characterization typically conditions fracture porosity (Fpor) on lithofacies classification, on the assumption that facies labels capture the geological controls on fracture development. This study evaluates this premise by employing a two-scale statistical decomposition of Fpor variance across 537 samples from 13 wells within a single field in the Malay Basin. The analysis uses FMI-derived Fpor as the reference and the operator's three-class lithofacies scheme (clean limestone, mixed carbonate, tight shaly carbonate) as the facies framework. The lithofacies classification produces a statistically detectable but quantitatively small effect on Fpor (one-way ANOVA F = 3.85, p = 0.022, η² = 0.014; Kruskal-Wallis H = 12.80, p = 0.0017, ε²H = 0.020), accounting for 1.4 to 2.0% of total variance. Tukey HSD pairwise testing localizes the signal to a single contrast between clean limestone and mixed carbonate (p-adj = 0.016); mixed and tight shaly carbonate classes are statistically indistinguishable (p-adj = 0.482). Well identity, in contrast, accounts for approximately 27% of total Fpor variance (Kruskal-Wallis ε²H = 0.271), an effect more than thirteen times larger than the facies effect. Ward hierarchical clustering on standardized per-well statistics partitions the wells into three internally consistent clusters that cross-cut lithofacies composition. Depth is excluded as a confounding variable through within-class correlation analysis. The dominant control on fracture porosity in this dataset operates at the well scale, not the facies scale. Geological similarity between the target and training wells is the binding constraint on the quality of blind-well fracture prediction. These results indicate that carbonate fracture-prediction workflows should replace facies-only conditioning with well-partitioned validation and well-scale distributional descriptors, since the current three-class lithofacies scheme resolves less than one-fifteenth of the variance that well identity alone explains. Structural compartmentalization is a plausible candidate mechanism, though untestable with the present dataset.
A Practical Integrated Workflow for Well Candidate Selection in Mature Oil Fields Using Well Opportunity Index and Delta Potential Amega Yasutra; Adam Muhammad
Scientific Contributions Oil and Gas Vol 49 No 3 (2026)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v49i3.2137

Abstract

Mature oil fields commonly face production decline, increasing water cut, and limited availability of complete static and dynamic reservoir models. Under these conditions, a practical and traceable workflow is necessary to select well candidates for production optimization. This study proposes an integrated workflow combining well opportunity index (WOI), Delta Potential, quadrant analysis, and weighted ranking. The workflow is applied to three producing wells in the G-40 sandstone reservoir of the TM Field, a mature oil field in the South Sumatra Basin, Indonesia. Current oil saturation is estimated using a fractional-flow-based approach and validated by matching calculated and observed oil rates, resulting in Mean Absolute Percentage Error (MAPE) values of approximately 2%, 3%, and 3%. WOI represents reservoir opportunity through flow capacity, movable hydrocarbon pore volume, and remaining pressure support, while Delta Potential quantifies remaining production opportunity. The calculated Delta Potential values are 0.112, 0.103, and 0.042 MMSTB for TM-1, TM-2, and TM-3, respectively. Quadrant analysis places TM-1 and TM-2 in the high-WOI and high-Delta-Potential region; however, TM-2 is treated as a secondary candidate requiring further diagnosis because its WOI is lower than that of TM-1. The final weighted ranking produces the priority order TM-1 > TM-2 > TM-3. These results indicate that the proposed workflow provides a practical and traceable preliminary screening tool for mature-field production optimization under limited data availability.
Determination of an Appropriate Method and Economic Cost Estimation for Plug and Abandonment of H-11 Well in The Tambun Field Luky Agung Yusgiantoro; Dedi Kristanto; Dimas Suryo Wicaksono; Karina Larasati; Vania Raina Stephanie; Gondo Irawan
Scientific Contributions Oil and Gas Vol 49 No 3 (2026)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v49i3.2141

Abstract

In accordance with Indonesian regulations, oil and gas wells approaching the end of their productive life and no longer economically viable must undergo plug and abandon (P&A) operations. The associated costs are the responsibility of the operating company. Therefore, operator must conduct technical and economic assessments to ensure that P&A operations are performed cost-effectively while complying with safety requirements, operational standards, and applicable national regulations. This study compares two plugs and abandonment methods for a directional well by evaluating the technical and economic performance of the SNI 13-6910-2002 and NORSOK Standard D-010. The Tambun field comprises several production wells, including the H-11 well, which was selected as the reference case  for planning permanent abandonment after reaching its economic limit. The P&A design was developed by identifying the well sections requiring cement isolation and calculating the required volumes of  cement, additives, and completion fluids using the rig-based abandonment method. The results provide an appropriate abandonment strategy and costs estimate for the tH-11 well based on both standards. The estimated abandonment cost is USD 505,737.59 using SNI 13-6910-2002, compared with USD 1,170,558.11 using NORSOK Standard D-010. Based on the comprehensive technical assessment, operational safety considerations, regulatory compliance, and economic evaluation, SNI 13-6910-2002 is recommended as the most suitable method for the permanent plug and abandonment of the H-11 well in Tambun field.
Unsupervised Machine Learning for Reservoir Rock Type Classification in the Ngimbang Formation, Northeast Java Basin, Indonesia Elizia Da Costa Alves; A.K.M. Eahsanul Haque; M. Azuwan B. Maoinser
Scientific Contributions Oil and Gas Vol 49 No 3 (2026)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v49i3.2147

Abstract

Reservoir characterisation is a fundamental step in hydrocarbon exploration and production, requiring accurate identification of rock types and productive zones. Conventional petrophysical analysis alone is often insufficient to capture the full complexity of heterogeneous carbonate formations. This study applies unsupervised machine learning, specifically K-means clustering, to classify reservoir rock types within the Lower Ngimbang Formation of the AXEL Field, Northeast Java Basin, Indonesia. Wireline log data from two wells  AXEL-1 and AXEL-2 comprising Gamma Ray (GR), Deep Resistivity (ResD), Neutron Porosity (NPHI), Bulk Density (RHOB), and Sonic (DT) logs were used as input. Quantitative petrophysical analysis was first conducted to estimate shale volume (Vsh), effective porosity (PHIE), and water saturation (Sw) using  Indonesian Equation. K-means clustering was subsequently applied, starting from 20 initial micro-clusters that were progressively consolidated into five geologically meaningful rock types: Hydrocarbon, Water-Bearing, Tight Formations, Coal, and Shale. The selection of five final groups was guided by a two-step validation approach using the Cluster Groups Randomness variance ratio generated within Interactive Petrophysics, which confirmed K=5 as the most geologically defensible configuration. In AXEL-1 Zone 1 yielded a net pay of 46.82 m (avg PHIE = 0.089, avg Sw = 0.352), confirmed by DST gas flow rates of up to 7.599 MMCFGPD, while AXEL-2 Zone 1 returned a net pay of 12.50 m (avg PHIE = 0.095, avg Sw = 0.057) reflecting lower hydrocarbon potential. The Hydrocarbon Potential facies (Group 3) identified by K-means showed strong spatial agreement with conventionally defined productive zones. These results demonstrate that unsupervised machine learning provides a practical and reproducible complementary framework for reservoir characterisation and rock type classification in complex carbonate reservoirs.
Mitigating Sulfate-Reducing Bacteria in Produced Water: Performance of MB-X Biocide Assessed by Sulfate-Reducing Bacteria Biological Activity Reaction Test at Regional 1 Sumatera Erik Indra Putra; Maulana Hardi; Oktaviani Kusuma Wardani
Scientific Contributions Oil and Gas Vol 49 No 3 (2026)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v49i3.2068

Abstract

Sulfate-reducing bacteria (SRB) are major drivers of microbiologically influenced corrosion (MIC) and reservoir souring in waterflooding operations, particularly in mature onshore assets with high produced-water volumes. This is showing the need for effective control of SRB to mitigate potential risks and maintain the integrity of waterflooding operations. Therefore, this study is aiming to evaluate the efficacy of the biocide MB-X at multiple doses (50-200 ppm) in suppressing SRB activity and population using the SRB-BART (Biological Activity Reaction Test). The experiment is being conducted by collecting produced-water samples from the Outlet WT at Field MX, followed by daily monitoring of SRB activity to determine the reaction day. The data obtained are being converted into population estimates (CFU/mL) according to the commercial kit guidance: Day-3 = 1.15 × 10⁵ CFU/mL; Day-4 = 2.7 × 10⁴ CFU/mL; Day-10 = 5 CFU/mL; Day-11 < 1 CFU/mL. Aggressiveness is being classified according to the kit scoring, namely Aggressive, Not Aggressive, and Negative. The results are showing that the control (blank) is showing a BB-type SRB consortium (anaerobe-dominant), with 1.15 × 10⁵ CFU/mL being classified as Aggressive. MB-X 50 ppm is reducing the population to 2.7 × 10⁴ CFU/mL, but the response is remaining Aggressive. In comparison, MB-X 100 ppm is suppressing counts to 5 CFU/mL (Not Aggressive), while MB-X 200 ppm is yielding a Negative response, showing undetected SRB activity. These results are indicating that MB-X at ≥100 ppm is effectively controlling SRB under test conditions, with 200 ppm achieving apparent eradication as detected by SRB-BART. However, interpretation of the statistical outcomes is being constrained by the limited number of treatment replicates, suggesting that the results should be considered a preliminary site-specific evaluation of MB-X performance. Consequently, future studies are being recommended to conduct field verification through replication, matrix controls, and in-situ corrosion monitoring to confirm performance durability.

Page 1 of 4 | Total Record : 35

 1   2   3   4 

Filter by Year

2026 2026


Reset
Filter By Issues
All Issue Vol 49 No 3 (2026) Vol 49 No 2 (2026) Vol 49 No 1 (2026) Vol 48 No 4 (2025) Vol 48 No 3 (2025) Vol 48 No 2 (2025) Vol 48 No 1 (2025) Vol 47 No 3 (2024) Vol 47 No 2 (2024) Vol 47 No 1 (2024) Vol 46 No 3 (2023) Vol 46 No 2 (2023) Vol 46 No 1 (2023) Vol 45 No 3 (2022) Vol 45 No 2 (2022) Vol 45 No 1 (2022) Vol 44 No 3 (2021) Vol 44 No 2 (2021) Vol 44 No 1 (2021) Vol 43 No 3 (2020) Vol 43 No 2 (2020) Vol 43 No 1 (2020) Vol 42 No 3 (2019) Vol 42 No 2 (2019) Vol 42 No 1 (2019) Vol 41 No 3 (2018) Vol 41 No 2 (2018) Vol 41 No 1 (2018) Vol 40 No 3 (2017) Vol 40 No 2 (2017) Vol 40 No 1 (2017) Vol 39 No 3 (2016) Vol 39 No 2 (2016) Vol 39 No 1 (2016) Vol 38 No 3 (2015) Vol 38 No 2 (2015) Vol 38 No 1 (2015) Vol 37 No 3 (2014) Vol 37 No 2 (2014) Vol 37 No 1 (2014) Vol 36 No 3 (2013) Vol 36 No 2 (2013) Vol 36 No 1 (2013) Vol 35 No 3 (2012) Vol 35 No 2 (2012) Vol 35 No 1 (2012) Vol 34 No 3 (2011) Vol 34 No 2 (2011) Vol 34 No 1 (2011) Vol 33 No 3 (2010) Vol 33 No 2 (2010) Vol 33 No 1 (2010) Vol 32 No 3 (2009) Vol 32 No 2 (2009) Vol 32 No 1 (2009) Vol 31 No 3 (2008) Vol 31 No 2 (2008) Vol 31 No 1 (2008) Vol 30 No 3 (2007) Vol 30 No 2 (2007) Vol 30 No 1 (2007) Vol 29 No 3 (2006) Vol 29 No 2 (2006) Vol 29 No 1 (2006) Vol 28 No 3 (2005) Vol 28 No 2 (2005) Vol 28 No 1 (2005) Vol 27 No 3 (2004) Vol 27 No 2 (2004) Vol 27 No 1 (2004) Vol 26 No 2 (2003) Vol 26 No 1 (2003) Vol 25 No 3 (2002) Vol 25 No 2 (2002) Vol 25 No 1 (2002) Vol 24 No 2 (2001) Vol 24 No 1 (2001) Vol 23 No 3 (2000) Vol 23 No 2 (2000) Vol 23 No 1 (2000) Vol 22 No 2 (1999) Vol 22 No 1 (1999) Vol 21 No 2 (1998) Vol 21 No 1 (1998) Vol 18 No 2 (1995) Vol 18 No 1 (1995) Vol 17 No 1 (1994) Vol 16 No 1 (1993) Vol 15 No 1 (1992) Vol 14 No 2 (1991) Vol 14 No 1 (1991) Vol 13 No 1 (1990) Vol 12 No 1 (1989) Vol 11 No 1 (1988) Vol 10 No 3 (1987) Vol 10 No 2 (1987) Vol 10 No 1 (1987) Vol 9 No 1 (1986) Vol 8 No 2 (1985) Vol 8 No 1 (1985) Vol 7 No 2 (1984) Vol 7 No 1 (1984) Vol 6 No 1 (1983) Vol 5 No 2 (1982) Vol 5 No 1 (1982) More Issue