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All Journal Journal of Petroleum and Geothermal Technology Journal of Earth Energy Science, Engineering, and Technology
Nugraha, Fanata Yudha
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Earth & Planetary Sciences Energy Engineering

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Implementation of CO2 Source-Sinks Match Database Development. Case Study: West Java Tony, Brian; Nugraha, Fanata Yudha; Al Hakim, Muhamad Firdaus; Putra, I Putu Raditya Ambara; Chandra, Steven
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.v5i2.13432

Abstract

Carbon capture and storage (CCS) is widely recognized as a significant technology in mitigating carbon dioxide (CO2) emissions from major industrial facilities, such as power plants and refineries. CCS involves the capture of concentrated CO2 streams from point sources, followed by subsequent safe and secure storage in appropriate geological reservoirs. We developed spatial database system using Geographic Information System (GIS) tools to facilitate source-sink matching between CO2 emitter and CO2 storage to foster the implementation of CCS/CCUS technologies in Indonesia. In this study, we proposed workflow approach to determine the location of CO2 sinks/storage candidates given limited data available. Additionally, this method spatially characterizes and represents probable clusters where opportunities for CCS/CCUS implementation are present. We consider the existing pipeline route and Right of Ways (ROW) to minimize the potential cost related to transportation of CO2 using pipeline. The priority of available storage is classified based on the storage capacity, distance, and other technical criteria to determine the optimal location of potential CO2 injection. We applied the workflow to Coal Fired Power Plant in West Java as the CO2 source, and we obtained 6 depleted fields that are connected to the existing ROW with CO2 storage capacity of 42.03 MMT.
Synthesis of Synthetic Brine to Estimate Carbonate Scale Index in Oil Industry Nugraha, Fanata Yudha; Asmorowati, Dewi; Saputra, Ega Dimas; Astuti, Dian Indri; Tony, Brian; Waisnawa, I Putu Gema Bujangga
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.v5i2.13636

Abstract

The decreased oil production due to scaling in production equipment results in costs. In oil wells, ions such as calcium, barium, carbonate, sulfate, magnesium, sodium, and chloride are commonly present in formation water. Excessive solubility of ions can trigger precipitation or what is often called scale. This study focuses on creating synthetic brine with a composition resembling field formation water as an alternative solution for rapid laboratory-scale measurement of the scale index. In this study focus on carbonate and bicarbonate scale. The stages of the research involves synthetic brine preparation, physical and chemical testing of the brine, comparison with formation water, and calculation of the Stability Index (SI) using Stiff & Davis method. The results indicate that synthetic brine can be prepared based on laboratory analysis of field samples by estimating the materials and masses present in formation water, thus allowing replication using natural or chemical materials in the laboratory while considering parameters such as pressure, temperature, and pH during the manufacturing process. The pH significantly impacts the risk of scale formation, where a slightly basic pH, around pH 8, supports higher concentrations of carbonate ions (CO32-) and bicarbonate ions (HCO3-), thereby increasing the risk of scale formation.
Innovation in Hydraulic Fracturing Technology Using Ctafs in Production Optimization Strategy in Unconventional Reservoir Barnett Shale: A Geology and Rock Physics Based Approach Pratama, Fauzan Abiyyu; Nugraha, Fanata Yudha; Baiti, Aisah Nur; Damayanti, Nabila Zafira
Journal of Earth Energy Science, Engineering, and Technology Vol. 8 No. 2 (2025): JEESET VOL. 8 NO. 2 2025
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/xsetaz66

Abstract

The Barnett Shale is the largest unconventional hydrocarbon-producing rock formation in the United States. It consists of shale rocks with high-density mineral content such as smectite, silica, and carbonate, which result in low permeability and porosity. Hydraulic fracturing utilizing the coiled tubing activated frac sleeve completion system (CTAFS) is employed to enhance hydrocarbon production by fracturing the formation. The application of hydraulic fracturing can significantly boost production from the Barnett Shale. To optimize this method, geological analysis and rock physics properties are essential to derive parameters such as predictions of Young’s modulus and Poisson’s ratio in the exploration area. This study uses a systematic review approach based on previous research, supported by secondary data instrumentation including rock core validation and well data digitization, which are subsequently modeled into rock physics parameters. The rock physics model is used to simulate the elastic properties of the rock formation, considering the matrix, constituent composition, and rock heterogeneity. Furthermore, hydraulic fracturing simulations are conducted to predict production and determine the resulting strategies. The research findings indicate that in the interval 10,650–10,725 ft of the EnerGeo1 well, kerogen volumetrics are 18%, quartz 38%, clay 35%, and calcite 15%. The Young’s modulus value is 39.5 GPa, and the Poisson’s ratio is 25.2%, categorizing it as Type 1. In the interval 10,725–10,803 ft, kerogen volumetrics are 18%, quartz 32%, clay 41%, and calcite 16%. The Young’s modulus value is 37.1 GPa, and the Poisson’s ratio is 24.8%, categorizing it as Type 2. In the interval 10,803–10,880 ft, kerogen volumetrics are 19.6%, quartz 41%, clay 31%, and calcite 11%. The Young’s modulus value is 43.3 GPa, and the Poisson’s ratio is 26.6%, categorizing it as Type 3. The data reveals that Type 3 rocks are more suitable for hydraulic fracturing compared to Type 1. Meanwhile, Type 2 rocks are identified as being suitable for placing horizontal wells due to the clay and calcite matrix, which can prevent formation collapse. It can be concluded that integrating geological and rock physics data can yield a more efficient and innovative fracturing design, resulting in a production increase of up to 129% compared to previous production levels.
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.
Co-Authors Astuti, Dian Indri Baiti, Aisah Nur Boni Swadesi Chandra, Steven Damayanti, Nabila Zafira Dewi Asmorowati Helmy, Mia Ferian Muhamad Firdaus Al Hakim Pratama, Fauzan Abiyyu Putra, I Putu Raditya Ambara Saputra, Ega Dimas Susanti Rina Tony, Brian Waisnawa, I Putu Gema Bujangga