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Journal of Petroleum and Geothermal Technology
Published by Universitas Pembangunan Nasional Veteran Yogyakarta
ISSN : 27230988     EISSN : 27231496     DOI : https://doi.org/10.31315/jpgt.v1i1
Core Subject : Science, Engineering,
Earth & Planetary Sciences Energy Engineering
Journal of Petroleum and Geothermal Technology (JPGT) is a journal managed by Petroleum Engineering Department, Universitas Pembangunan Nasional "Veteran" Yogyakarta. This Journal focuses on the petroleum and geothermal engineering including; reservoir engineering, drilling engineering and production engineering.
Arjuna Subject : Teknik (semua kategori) - Teknik (Lain-Lain)
Articles 5 Documents
 1 
Search results for , issue "Vol 1, No 2 (2020): November" : 5 Documents clear
An Experimental Investigation the Optimum of Salinity and Ph of Sea-Water to Improve Oil Recovery from Sandstone Reservoir as A Secondary Recovery Process Madi Abdullah Naser; Mohammed A Samba; Yiqiang Li
Journal of Petroleum and Geothermal Technology Vol 1, No 2 (2020): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v1i2.3810

Abstract

Laboratory tests and field applications shows that the salinity of water flooding could lead to significant reduction of residual oil saturation. There has been a growing interest with an increasing number of low-salinity water flooding studies. However, there are few quantitative studies on seawater composition change and it impact on increasing or improving oil recovery.  This study was conducted to investigate only two parameters of the seawater (Salinity and pH) to check their impact on oil recovery, and what is the optimum amount of salinity and ph that we can use to get the maximum oil recovery.  Several core flooding experiments were conducted using sandstone by inject seawater (high, low salinity and different pH). The results of this study has been shown that the oil recovery increases as the injected water salinity down to 6500 ppm and when the pH is around 7. This increase has been found to be supported by an increase in the permeability. We also noticed that the impact of ph on oil recovery is low when the pH is less than 7.
Analysis Study Of The Effect In Selecting Combination Of Fracturing Fluid Types And Proppant Sizes On Folds Of Increase (FOI) To Improve Well Productivity Dimas Ramadhan; Hidayat Tulloh; Cahyadi Julianto
Journal of Petroleum and Geothermal Technology Vol 1, No 2 (2020): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v1i2.3886

Abstract

As fracturing materials, fracturing fluid and proppant are two very important parameters in doing hydraulic fracturing design. The combination of fractuirng fluid and proppant selection is the main focus and determinant of success in the hydraulic fracturing process. The high viscosity of the fracturing fluid will make it easier for the proppant to enter to fill the fractured parts, so that the conductivity of the fractured well will be better and can increase the folds of increase (FOI) compared to fracturing fluid with lower viscosity (Economides, 2000). This research was conducted by using the sensitivity test method on the selection of fracturing fluid combinations carried out at the TX-01 well with various sizes of proppants (namely; 12/18, 16/20, and 20/40 mesh) with the proppant selected being ceramic proppant type carbolite performed using the FracCADE simulator. Fracturing fluid was selected based on its viscosity, namely YF240OD and PrimeFRAC20 fluids with viscosity value of 4.123 cp and 171.1 cp, with a fixed pump rate of 14 bpm. The results showed that the combination of high-viscosity fluids (PrimeFRAC20) and 16/20 mesh proppant size resulted in a greater incremental fold (FOI) between the choice of another combination fracturing fluids and proppant sizes, namely 6.25.
Application of Fracture Barrier Analysis in Well Stimulation Planning for Upper Baturaja Limestone Formation Based on Well Log & Drill Cutting Data from OBF-01 and OBF-04 Wells, Offshore Southeast Sumatra Aris Buntoro; Muhammad Nurcholis; Basuki Rahmad; Allen Haryanto Lukmana; Ristiyan Ragil Putradianto
Journal of Petroleum and Geothermal Technology Vol 1, No 2 (2020): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v1i2.3686

Abstract

In general, the South Sumatra Regional Stratigraphy of the Baturaja Limestone Formation facies is deposited on the Buildup Carbonate (Reef) and the Limestone Clastic Carbonate of the Baturaja Formation which grows as a buildup reef on the platform in the Basement High (Horst) underneath is the Lemat Formation volcanic deposits. Referring to the facies model in general, the Baturaja Limestone Formation, the depositional environment starts from Shelf Lagoon Open Circulation - Winnowed Edge Sand - Organic Buildup - Fore Slope - Deep Shelf Margin - Open Sea Shelf - Basin, meaning that carbonate is formed starting from pure organic Cabonate Buildup Reef without / a little sludge / mud to the Carbonate Basin where more muddy / mud is present, this condition causes clay minerals to also more and more mix with Terigenous Clastics (Quartz, feldpar). The complexity of the Baturaja Limestone Formation requires fracture barrier analysis associated with well stimulation planning in order to increase oil productivity with the appropriate method.   Fracture barrier fracture analysis is an approach method to determine the depth interval that becomes a barrier in hydraulic fracturing by correlating the results of geomechanical analysis from well log data and mineralogical analysis from drill cuttings data, so that a commonly used well stimulation method can be selected, namely hydraulic fracturing, acidizing, and acid-fracturing.From the ternary diagram plot the XRD (bulk) analysis results show that the distribution of the main minerals (Quartz, Clay, Calcite) is more dominant in the ductile zone, hard to frac category. This shows that all the depth intervals in the OBF-01 and OBF-04 wells are more ductile, and are not recommended for hydraulic fracturing. From the XRD (bulk) analysis, Calcite mineral is more dominant, so for well stimulation work it is recommended to use acidizing or acid-fracturing.
Securing Annulus Abnormal Pressure Build-up (APB) with Polymer Plug; a Case Study Ganesha R Darmawan
Journal of Petroleum and Geothermal Technology Vol 1, No 2 (2020): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v1i2.3825

Abstract

The life cycle of a production well was facing challenges related to well integrity issue where A-Annulus pressure tracking the tubing pressure and increased repeatedly above the Maximum Allowable Wellhead Operating Pressure (MAWOP). Several well control operations were executed to reduce A-Annulus abnormal pressure build-up (APB) with no success.Literature and well historical studies were performed in order to secure this well, normal bleed and lube was ruled out owing to several attempts already performed for more than a year, but the APB keep on appearing after 2-4 months. Bullheading is not a viable option to kill the well. Well securing planned and prepared with some options such as, mechanical barriers/plugs, cement plug or polymer plugs as temporary plug to avoid APB re-occurrence. There were some constrains in operation planning that need to be addressed carefully, with additional challenge of tight injectivity as if it was a closed system.The polymer plug successfully stops the gas migration to surface, and secured the well from any reoccurrences of APB. The details of well control histories, operation design and planning and operation execution with the complete results and evaluation will be presented in this paper.
Simulation Study of Fluid Flow and Estimation of a Heterogeneous Porous Media Properties Using Lattice Gas Automata Method Dedy Kristanto; Windyanesha Paradhita
Journal of Petroleum and Geothermal Technology Vol 1, No 2 (2020): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v1i2.3856

Abstract

Most models used in reservoir simulation studies are on the scale of meters to hundreds of meters. However, increasing resolution in geological measurements results in finer geological models. Simulations study of particle movements provide an alternative to conventional reservoir simulation by allowing the study of microscopic and/or macroscopic fluid flow, which is close to the scale of geological models. In this paper, the FHP-II (Frisch, Hasslacher and Pomeau - FHP) model of lattice gas automata were developed to study fluid flow in order to estimate the properties of heterogeneous porous media. Heterogeneity simulated by placing solid obstacles randomly in a two-dimensional test volume. Properties of the heterogeneous porous media were estimated by the shape, size, number of the obstacles and by the distribution of the obstacles within the volume. Results of the effects of grain sizes and shapes, and its distribution in the porous media on the tortuosity, effective porosity, permeability and displacement efficiency were obtained. An investigation of fluid flow and comparison with laboratory experiment were also presented. Reasonably good agreement between the lattice gas automata simulation and laboratory experiment results were achieved.

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