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All Journal Journal of Petroleum and Geothermal Technology Petro : Jurnal Ilmiah Teknik Perminyakan Scientific Contributions Oil and Gas LEMBARAN PUBLIKASI MINYAK DAN GAS BUMI (LPMGB)
Mohd Wirawan Putra Pamungkas
Universitas Sriwijaya
Chemical Engineering, Chemistry & Bioengineering Earth & Planetary Sciences Economics, Econometrics & Finance Energy Engineering

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HYDRAULIC FRACTURING EVALUATION OF WELL ZAA-011 PANGKALAN SUSU FIELD, NORTH SUMATRA Pamungkas, Mohd. Wirawan Putra
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.v5i2.13268

Abstract

Well ZAA-011 is a well located in the Pangkalan Susu field that has been depleted, where the reservoir has experienced a decrease in producing ability due to fair permeability. Well ZAA-011 produces with artificial lift in the form of a hydraulic pumping unit (HPU) and has a water cut value of 72%. The well is producing in sandstone Structure B, located at a depth of 3392 - 3412 ft MD, with a reservoir pressure of 606 psia. Well ZAA-011 has a permeability of 10 mD or fair and a productivity index of 1.084 bpd/psi. The method used to evaluate hydraulic fracturing stimulation in the ZAA-011 well is by using MFrac simulation which is an evaluation measurement in the previous hydraulic fracturing process. The fracture properties parameters are fracture half-length, fracture width, fracture height, fracture conductivity, dimensionless frac conductivity, and reservoir permeability. Production parameters are seen through pipesim simulation in the form of nodal analysis to see the optimal production rate. Economic parameters using profit indicators are calculated with the production sharing contract model cost recovery model including NPV, IRR, ROI and POT obtained. Based on the simulation using MFrac software, the hydraulic fracturing design values are fracture half-length 34.239 m, fracture width 0.37321 inch, fracture height 14.42 m, fracture conductivity 12984 mD-ft, dimensionless frac conductivity 6.4239. Permeability was found to be 37 mD and theoretically the average is about 36.7 mD and the productivity index also increased by 2.383 bpd/psi. Plus nodal analysis in the wellbore using pipesim software obtained a production rate of 238.8 BLPD (67.54 BOPD). Economic analysis using profit indicators obtained an NPV value of MUS$ $937, IRR with a value of 250.71%, ROI of 77.22% and POT obtained 0.354 years or about 4,248 months. This indicates that the redesign work on hydraulic fracturing in the ZAA-011 well is effective and optimal.
Impact Assessment of Wax Gelation Fluid Pressure and Temperature: Designing Long-Term Preventive Solutions Hasan, Meutia Fitri; Lestari, Venty; Budiman, Hendra; Setiawan, Aldo; Pamungkas, Mohd Wirawan Putra
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.v48i4.1932

Abstract

Paraffinic precipitation presents a pervasive flow challenge, specifically impacting this light crude oil (API 34.85 °) system, particularly within a pipeline (length 1153 m) operating in cold environments. This study first rigorously assessed the critical impact of flow parameters, confirming the fluid’s thermal profile drops below the pour point (31.67 oC) at a crucial distance of 439.24 m from the wellhead, initiating severe wax gelation. Flow analysis further confirms a detrimental laminar flow regime (NRe = 1262), which, coupled with a significant total pressure drop of 0.155 psia/100 ft along the pipeline, exacerbates the tendency for solidified paraffins to accumulate due to insufficient shear stress. To address this, the research successfully validated a cost-effective, long-term preventative solution: a locally fabricated sand heater with an energy capacity of 175,000 kcal/h. Empirical field testing confirmed the intervention provides a substantial net thermal elevation of 8.5 oC. Subsequent thermal modeling for long-term operational reliability identified the optimal sand-heater placement distance to be within 300 m of the wellhead. This strategic placement ensures the fluid temperature consistently remains safely above the pour point, effectively mitigating the risk of premature wax gelation and guaranteeing uninterrupted system integrity and sustained hydrocarbon production.
OPTIMALISASI BERTINGKAT BERBASIS INTEGRITAS ELASTOMER PROGRESSIVE CAVITY PUMP (PCP) Mohd Wirawan Putra Pamungkas; Hendra Budiman
Petro : Jurnal Ilmiah Teknik Perminyakan Vol. 15 No. 2 (2026): Juni 2026
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.v15i2.26246

Abstract

This research aims to optimize oil recovery through technical evaluation and redesign of the Progressing Cavity Pump (PCP) artificial lift system in wells AW-01 and AW-02 at PT. Pertamina EP Asset 1 Jambi Field. The method used is formation productivity analysis using the Vogel Inflow Performance Relationship (IPR) curve, volumetric efficiency evaluation, Total Dynamic Head (TDH) calculation, and stator elastomer integrity threshold testing based on fluid abrasiveness and rotation speed (RPM). The results of this research activity are the identification of different optimization needs for both wells; AW-01 is optimized by increasing the Variable Speed Drive (VSD) frequency to 47 Hz (277 RPM) to reach 62% Qmax, while AW-02 requires a redesign using a 20 H 500 pump type to achieve the 80% Qmax target (791.348 bfpd) at a safe speed of 150 RPM. The Conclusion, Significance, and implications of the Research show that the tiered optimization strategy successfully increased production by 3.87 bopd for AW-01 and 9.45 bopd for AW-02. This study demonstrates that maintaining elastomer integrity by limiting RPM is crucial for preventing mechanical failure. The implication is that this approach provides a new operational standard in extending pump run life while maximizing reservoir potential economically and sustainably.
The Effect of Stroke Length and SPM Variations on Production Rate and Economic Profitability of AH-052 Well Mohd Wirawan; Novrianti; Aldo Setiawan
Lembaran publikasi minyak dan gas bumi Vol 60 No 1 (2026)
Publisher : BBPMGB LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/LPMGB.60.1.1914

Abstract

AH-052 well, which uses a Sucker Rod Pump (SRP), began to experience a decline in productivity over time. The performance of the AH-052 oil well in South Sumatra, which uses a Sucker Rod Pump (SRP) as an artificial lift system. This well has a depth of 289.87 meters with a perforation interval of 236.52–238.05 meters. Before optimization, this well showed a production rate of 264 BFPD with a water cut of 97% and a pump efficiency of only 72.28%. Through variations in the SRP pump system parameters, the available equipment specifications were 1 1/4 inch and 1 1/8 inch rods, rod number 109, plunger 2 inch, stroke length (SL) of 140 inch, and pump speed (n) of 5 spm. The parameters used successfully increased pump efficiency significantly to 91.12% and production rate to 381.2 BFPD. Economic feasibility analysis based on the Production Sharing Model Contract Cost Recovery contract model showed very positive results. This project generated a Net Present Value (NPV) of MU$202.08, an Internal Rate of Return (IRR) of 1153%, a Pay Out Time (POT) of 0.086 years, and a Profitability Index (PI) of 22.56. Based on these indicators, this optimization project is considered highly financially viable and provides substantial benefits.
Desain dan Karakterisasi Kinerja Electric Submersible Pump (ESP) Khusus Sumur Kandungan Gas Liquid Ratio (GLR) Tinggi: Analisis Ekonomi dan Kelayakan Investasi Mohd Wirawan Putra Pamungkas
Lembaran publikasi minyak dan gas bumi Vol 59 No 3 (2025)
Publisher : BBPMGB LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/LPMGB.59.3.1915

Abstract

The decline in oil well production is caused by natural factors such as reservoir pressure decline, increased water content, and high gas-liquid ratio (GLR), which also affect artificial lift performance. Electric Submersible Pump (ESP) is chosen as a solution, despite challenges such as gas lock and uneven wear in high GLR directional wells. ESP planning focused on component design, such as motor protectors and the use of Single Feature Rotary Gas Separators to address gas issues. The implementation of ESP in three wells showed a significant increase in production: Well AZ-049 increased by 12.7% (from 902 BFPD to 1017 BFPD), Well AZ-084 increased by 86%, and Well AZ-025 achieved the highest increase of 124% (from 246 BFPD to 551 BFPD). Collectively, this project generated a total gross production of 2817 BFPD and a net oil gain of 364.5 BOPD. Economic analysis shows excellent financial viability with a Net Present Value (NPV) of $3.089 million, a Profitability Index (PI) of 30.07, and a Rate of Return (ROR) of 2761.33%. Liquidity risk is very low, indicated by a Pay Out Time (POT) of only 0.035 years (approximately 13 days). These results indicate that the ESP project is a highly potential investment.
Co-Authors Aldo Setiawan Hasan, Meutia Fitri Hendra Budiman Hendra Budiman Novrianti Novrianti Setiawan, Aldo Venty Lestari