Article Per Year (5 Year)
p-Index From 2021 - 2026
0.61
P-Index
This Author published in this journals
All Journal Techno LPPM Journal of Petroleum and Geothermal Technology Journal of Earth Energy Science, Engineering, and Technology
Helmy, Mia Ferian
Unknown Affiliation
Earth & Planetary Sciences Energy Engineering

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

Found 3 Documents
Search

 1 
Hydraulic Fracturing Stimulation Planning of “X” Well in Talang Akar Formation Helmy, Mia Ferian; Nugraha, Fanata Yudha; Boni Swadesi; Dewi Asmorowati; Susanti Rina
Journal of Earth Energy Science, Engineering, and Technology Vol. 8 No. 1 (2025): JEESET VOL. 8 NO. 1 2025
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/arygvm79

Abstract

“X” well is a well with a productive sandstone formation with a productivity index of 0.1 bfpd/psi. Hydraulic fracturing will be performed based on screening results, with design simulated using commercial software. The design process includes analyzing well data, reservoir characteristics, and rock geomechanics using the Perkins, Kern, and Nordgren (PKN) fracture model. The chosen fracturing fluid is YF135.1HTD with Carbolite Proppant (12/18 mesh). The geometric model applied uses the PKN method with results of a fracture length of 463.9 ft, fracture height of 9.84 ft, fracture width of 0.37 inch, and fracture conductivity of 77063 md.ft using a total volume of fracturing fluid of 13500 gallons and a total mass of proppant. amounting to 40590 lbs. The required surface injection pressure is 4176.13 psi with an injection rate of 18 bpm and a total pumping time of 20.2 minutes. The performance improvement of the “X” well was in the form of average formation permeability from 29.2 mD to 369.4 mD, an increase in productivity index of 6.5 times and an increase in production rate from 50.46 bfpd to 296.48 bfpd. So, the planning of the hydraulic fracturing design for the “X” Well can be considered for implementation.
Polymer Injection Modeling in a Solution Gas Drive-Naturally Fractured Reservoir Widiyaningsih, Indah; Helmy, Mia Ferian; Kaesti, Edgie Yuda; Arta, Atma Budi
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.v7i1.4479

Abstract

Solution Gas Drive-Naturally Fractured Reservoir (NFR) has relatively high remaining oil reserves. This causes less optimum oil from the reservoir to be produced to the surface, so that it requires an enhanced oil recovery (EOR). EOR can be done by chemical injection, one of which is by polymer injection. Polymer injection emphasizes improving the swept efficiency. The most important parameter in this case is the mobility ratio. The injection process is very dependent on reservoir fluid characteristics, rock heterogeneity, and interactions between fluid and rock. Therefore, studies are needed to understand the mechanism of polymer injection that occurs in the reservoir.Simulation modelling of polymer injection on solution gas drive naturally fractured carbonate reservoir will be done using a black-oil simulator. In the black oil simulator it can be observed changes in the parameters of the mobility ratio of water to oil. In this simulation will run water flooding case as comparison to polymer injection case.The purpose of this study is to observe an increase in recovery factor with water flooding and polymer injection scenario on solution gas drive-NFR. The scenario that provides the greatest recovery factor can be considered in carrying out a strategy to increase oil recovery at EOR methods.
Evaluation of HPU Performance in High GLR Oil Well BNG-X3 Benuang Field South Sumatera Pramana, Edho; Suranto; Helmy, Mia Ferian; Bintarto, Bambang; Rahmadhini, RR Rahajeng Suryo; Wicaksono, Dimas Suryo
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.v6i2.14921

Abstract

Nowadays, producing BNG-X3, a well in Benuang Field, is relatively easy due to its natural drive which is bottom water aquifer combined with high associated gas content. Hence, most of the wells are flowing naturally from reservoir to surface facilities. However, issues most likely to occur overtime, especially when the pressure depletes due to production hence could not supply enough energy for the fluid to flow naturally. In this study, analysis was conducted to address this future problem by implementing a suitable artificial lift for this kind of circumstances. To get a more sustainable and continuous result, post installation evaluation was carried out to define key parameters that can lead to success and optimization in future application of Hydraulic Pumping Unit (HPU) in Benuang Field. The analysis consists of reserve calculations, economic feasibility, and step by step design for artificial lift HPU. The HPU installation and production performance monitoring for well BNG-X3 were conducted thoroughly to assess whether the implementation was optimized based on the well’s potential. Reserve calculations were performed using the Decline Curve Analysis (DCA) method and Pipesim software, while the HPU design was developed using Microsoft Excel. Field data was utilized for monitoring and evaluating the results. Based on the analysis, well BNG-X3 still holds significant potential. From an economic perspective, it has a positive Net Present Value (NPV) of $615,000 and a Payback Period (POT) of less than one year. Production observations indicate that well BNG-X3, with a Gas-Liquid Ratio (GLR) of up to 1000 SCF/STB and a high gas production rate, can be reactivated. The use of a 2.5” pump, along with SPM 5 and SL 155-inch parameters, has been fairly successful in restoring lost production. However, the achieved production rate has not yet reached the well's optimal potential due to the pump efficiency still being below the target (67%).
Co-Authors Arta, Atma Budi Bintarto, Bambang Boni Swadesi Dewi Asmorowati Edgie Yuda Kaesti Nugraha, Fanata Yudha Pramana, Edho Rahmadhini, RR Rahajeng Suryo Suranto Susanti Rina Wicaksono, Dimas Suryo