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All Journal Journal of Petroleum and Geothermal Technology Journal of Earth Energy Science, Engineering, and Technology Scientific Contributions Oil and Gas
Nugraha, Fanata Yudha
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Chemical Engineering, Chemistry & Bioengineering Earth & Planetary Sciences Energy Engineering

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Journal : Journal of Earth Energy Science, Engineering, and Technology

 1 
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.
Optimization of Hydraulic Fracturing Modeling on The Proppant Flowback Issue Well DF-007 Nugraha, Fanata Yudha; Cahyaningtyas, Ndaru; Addin, Dhaffa Izuddin; Tony, Brian; Nandiwardhana, Damar
Journal of Earth Energy Science, Engineering, and Technology Vol. 8 No. 3 (2025): JEESET VOL. 8 NO. 3 2025
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25105/dkvxbf52

Abstract

Well DF-007, Field IA, Talang Akar Formation has low permeability that hinders well productivity. To improve production performance, hydraulic fracturing operations need to be conducted on the well. However, after the operation, a proppant flowback problem was discovered when the well was put back into production. This issue disrupts production performance and causes proppant accumulation. This problem indicates the need for a comprehensive analysis of the factors leading to proppant flowback issues, before determining a solution that addresses the root cause of the problem. The research flow begins with analyzing the factors causing proppant flowback issues such as initial production management settings, mechanical, and hydrodynamic force factors. After identifying the main issue, which is the hydrodynamic force factor, the process continues to the re-modeling stage by selecting proppants and fracturing fluids. The solution is determined by selecting the YF135.1HTD fracturing fluid with high viscosity to optimize proppant transportation, as well as choosing a combination of conventional proppants and adding resin-coated or rod-shaped proppants in the final stage to strengthen the stability of the proppant layer. The evaluation results show that the use of a combination of the fracturing fluid YF135.1HTD and the proppants BorProp 16/20 (Ceramic) + 16/20 XRT Ceramax I (Resin Coated Ceramic) can increase the average formation permeability from 5.33 mD to 181 mD, skin factor from +11.65 (damaged) to -6.03 (stimulated), fold of increase (FOI) of 8.21 times, as well as an increase in the gross rate on the inflow performance relationship (IPR) from previously 88 BFPD to 880 BFPD.
Co-Authors Addin, Dhaffa Izuddin Astuti, Dian Indri Baiti, Aisah Nur Boni Swadesi Cahyaningtyas, Ndaru Chandra, Steven Damar Nandiwardhana, Damar Damayanti, Nabila Zafira Dewi Asmorowati Fatahillah, Azhar Faari Hariyadi Helmy, Mia Ferian Karina Larasati Muhamad Firdaus Al Hakim Pratama, Fauzan Abiyyu Putra, I Putu Raditya Ambara Saputra, Ega Dimas Susanti Rina Tony, Brian Waisnawa, I Putu Gema Bujangga