Article Per Year (5 Year)
p-Index From 2021 - 2026
0.61
P-Index
This Author published in this journals
All Journal Scientific Contributions Oil and Gas
Wardani, Oktaviani Kusuma
Unknown Affiliation
Chemical Engineering, Chemistry & Bioengineering Energy

Published : 3 Documents Claim Missing Document
Claim Missing Document
Check
Articles

Found 3 Documents
Search

 1 
Determination of Scale Inhibitor Effective Dose for Well A28 Using A Differential Scale Loop Method Hardi, Maulana; Pratamora, Rene Indrawan; Wardani, Oktaviani Kusuma; Meisinca, Dzulhijah Nur
Scientific Contributions Oil and Gas Vol 48 No 4 (2025)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/scog.v48i4.1826

Abstract

Well A28 in the Rokan Field has been identified with scale deposition on the surface flowline. The Scaling Index (SI) calculated using the Stiff and Davis method was +3.89, showing a high potential for aggressive scale formation. These deposits originate from mineral precipitation in produced water. To address this issue, scale inhibitor injection was applied, and the optimum dosage was determined using the Differential Scale Loop (DSL) method. This method evaluates inhibitor performance based on differential pressure caused by scale formation under field conditions (temperature 127 °C, flow rate 5 mL/min, operating pressure 300 psi). Tests were conducted using inhibitor doses of 25 ppm, 35 ppm, and 50 ppm. The results showed that a dose of 35 ppm produced the highest inhibition efficiency, reaching 100.3%, while also exhibiting minimal pressure drop. This dosage proved more effective than the other concentrations evaluated. Identifying this optimum dose supports reductions in chemical consumption and maintenance frequency, offering practical and cost-efficient benefits for field operations.
Reservoir Engineering Evaluation of Water Rock Compatibility and Permeability Damage in PX Field Rahayu, Cece; Hardi, Maulana; Rizqullah , Muhammad Daffa; Wardani, Oktaviani Kusuma
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.v49i1.1955

Abstract

Compatibility between injection fluids and reservoir rocks is a crucial factor in the success of waterflooding operations, particularly in reservoirs with complex characteristics. Therefore, this study aimed to evaluate injection water–reservoir rock compatibility from a reservoir engineering perspective, focusing on permeability impairment mechanisms associated with fine migration and suspended solids during water injection in the PX Field. Rock samples were obtained from a selected formation, while injection water was collected from the Water Injection Plant (WIP). Laboratory experiments were conducted by injecting both Total Suspended Solids (TSS)-free water and water containing TSS into 1.5-inch core plugs positioned vertically in a Hassler-type core holder under an overburden pressure of 1,725 psi, backpressure of 250 psi, and room temperature conditions. Moreover, the injection water viscosity during the process of the experiment was 0.95 cP. The results showed a pronounced permeability reduction of up to 98% in the PX Field sample. The permeability decline occurred rapidly and intermittently in distinct stages, which initially proposed clay swelling as a possible mechanism. However, X-ray diffraction (XRD) analysis presented negligible smectite content, excluding clay swelling as the dominant cause of damage. Permeability impairment was primarily attributed to pore blockage from fine migration and suspended particles, as supported by particle size distribution (PSD) and TSS analyses. These results showed the importance of comprehensive rock–fluid compatibility evaluation before water injection implementation to minimize formation damage and optimize waterflooding performance.
Evaluation of Chemical Acidizing Performance Using 15% Hydrochloric Acid (HCl) on Eight Production Wells in Field X Arjuna; Hardi, Maulana; Kuswardani, Tyas; Wardani, Oktaviani Kusuma
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.v49i1.2050

Abstract

This study evaluates the performance of matrix acidizing, a stimulation process conducted below fracturing pressure using 15% hydrochloric acid (HCl) on eight production wells in Field X, a carbonate reservoir. The assessment compares pre‑ and post‑treatment production performance over a defined 30‑day monitoring period. Acid selection was supported by laboratory dissolution analysis using β₁₀₀ and dissolution rate indicators, demonstrating that 15% HCl provided the strongest dissolving power against carbonate minerals compared with formic and acetic acids. The distinction between chemical acidizing (acid-based mineral dissolution) and matrix acidizing (operational mode focused on restoring near‑wellbore permeability without inducing fractures) is clarified to align with standard acidizing terminology. Field results show a 90% overall success rate, with average production gains of +778.76 BFPD (fluid) and +49.54 BOPD (oil). One well exhibited an anomalous response, characterized by an increased fluid rate but a reduced oil rate, indicating the potential activation of water-conductive pathways. These findings highlight that, although acid strength is an important factor, treatment success also depends on reservoir heterogeneity, scale distribution, and the effectiveness of acid placement. The integrated workflow combining Scale Index (SI) evaluation with dissolving‑power‑based acid screening provides a structured approach for designing matrix acidizing in mature carbonate fields.
Co-Authors Arjuna Hardi, Maulana Kuswardani, Tyas Meisinca, Dzulhijah Nur Pratamora, Rene Indrawan Rahayu, Cece Rizqullah , Muhammad Daffa