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All Journal Journal of Petroleum and Geothermal Technology Scientific Contributions Oil and Gas
Pamungkas, Mohd. Wirawan Putra
Universitas Sriwijaya
Chemical Engineering, Chemistry & Bioengineering Earth & Planetary Sciences 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 Mohd Wirawan Putra Pamungkas; Meutia Fitri Hasan; Venty Lestari; Hendra Budiman; Aldo Setiawan
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.
Co-Authors Aldo Setiawan hendra budiman Meutia Fitri Hasan Venty Lestari