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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 2, No 2 (2021): November" : 5 Documents clear
Risk Mitigation and Mapping on Tubular System During Microbial Huff and Puff Injection Coupled with Lean Six Sigma Approach at Field X Steven Chandra; Prasandi Abdul Aziz; Wijoyo Niti Daton; Muhammad Rizki Amrullah
Journal of Petroleum and Geothermal Technology Vol 2, No 2 (2021): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v2i2.4902

Abstract

Increasing demand of oil in Indonesia is in contrast with the decreasing oil production every year. Enhanced oil recovery (EOR) has become one of the most favorable method in maximizing the production of mature fields with various applications and research has been done on each type, especially microbial EOR (MEOR). “X” field is a mature oil field located in South Sumatra that has been actively producing for more than 80 years and currently implementing MEOR using huff and puff injection. However, there are some potential risks regarding MEOR processes that may inhibit the production by damaging the well’s tubular system, particularly microbially induced corrosion (MIC). This study reviews the risk mitigation and mapping to prevent corrosion on tubular system during MEOR huff and puff processes, equipped with the approach of Lean Six Sigma.The mitigation and mapping process follow the framework of define, measure, analyze, improve, and control (DMAIC). It starts with defining the problem using supplier-input-process-output-customer (SIPOC) diagram after all the field data necessary has already been collected, then measuring the corrosion rate model using ECE™ software as well as conducting sensitivity analysis of the fluid rates. The analyze phase involves constructing fishbone diagram to identify the root causes, comparison with industry’s specification and standard, and analysis of chromium effect on corrosion rates. Further simulation is conducted to support the analysis and to ensure the improvements and sustainability of the design selection.Based on the simulation results, the normal corrosion rate ranging from 0.0348 – 0.039 mm/year and the pH is around 4.03 – 5.25, while the ±30% fluid rate sensitivity results shown that the change of water flowrate is more sensitive than oil flowrate with the corrosion rate approximately 0.0275 – 0.048 mm/year. The fishbone diagram identifies that material selection and environmental condition as the main root causes, then corrosion resistant alloy (CRA) is used in the tubing string to prevent corrosion in the future by using super 13Cr martensitic steel (modified 2Ni-5Mo-13Cr) as the most suitable material. Further simulation on chromium content supports the selection that corrosion rate can be reduced by adding the chromium content in the steel. The completion design is then capped with choosing the Aflas® 100S/100H fluoro-elastomer as the optimum material for packer and sealing. Overall, the Lean Six Sigma approach has been successfully applied to help the analysis in this study.
Validation of The Cullender and Smith Method for Determining Pressure Loss in The Tubing in Gas Wells Muhammad Zakiy Yusrizal; Anas Puji Santoso
Journal of Petroleum and Geothermal Technology Vol 2, No 2 (2021): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v2i2.5657

Abstract

The ability of the reservoir to deliver a certain quantity of gas depends both on the inflow performance relationship and the flowing bottom hole pressure. In order to determine the deliverability of the total well system, it is necessary to calculate all the parameters and pressure drops, one of which in the tubing. Calculation of pressure loss in the tubing is a very important parameter in the stability of fluid flow from the reservoir to the surface. The calculation of pressure loss in the tubing which is most widely used in the field is the Cullender and Smith Method. The purpose of this study is to validate why the Cullender and Smith method is most widely used in the field to determine the pressure loss in the tubing compared to other pressure loss in tubing methods. The methodology used in this study is calculating the pressure loss in the tubing with the Average Temperature and Deviation Factor Method, the Sukkar and Cornel Method, and the Cullender and Smith Method. After calculating the pressure loss in the tubing using each of these methods, then comparing the percent error of the calculation method with the results in the well. The data used in the calculation is the data from the MZ Field from 7 wells in the East Kalimantan area. The results of the average error percentage obtained from this study are the Average and Deviation Factor Method is 5.38%, the Sukkar and Cornell Method is 5.65%, and the Cullender and Smith Method is 3.83%. From this study, it can be said that the Cullender and Smith Method to be valid or the most accurate method for used in the field compared to other methods due to resulting the smallest percent error from the calculation.
RESERVOIR PERFORMANCE ANALYSIS USING MATERIAL BALANCE METHOD IN GAS FIELD Indah Widiyaningsih; Panca Suci Widiantoro; Suwardi Suwardi; Riska Fitri Nurul Karimah
Journal of Petroleum and Geothermal Technology Vol 2, No 2 (2021): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v2i2.5503

Abstract

The RF reservoir is a dry gas reservoir located in Northeast java offshore that has been produced since 2018.  The RF reservoir has produced 2 wells with cumulative production until December 2019 is 31.83 BSCF. In January 2018 the gas production rate from the two wells was 36 MMSCFD and the reservoir pressure at the beginning of production was 2449.5 psia, peak production occurred in April 2019 with a gas flow rate of 98 MMSCFD but in December 2019 the gas production rate from both wells decreased to 30 MMSCFD with reservoir pressure decreased to 1607.8 psia. Changes in gas flow rate and pressure in the RF reservoir will affect changes in reservoir performance, so it is necessary to analyze reservoir performance to determine reservoir performance in the future with the material balance method. Based on the results the initial gas in place (IGIP) is 80.08 BSCF. The drive mechanism worked on the RF reservoir until December 2019 was a depletion drive with a recovery factor up to 88% and a current recovery factor (CRF) is 40%. The remaining gas reserves in December 2019 is 39 BSCF and the reservoir will be made a production prediction until December 2032. Based on production predictions of the four scenarios, scenario 2 was chosen as the best scenario to develop the RF reservoir with a cumulative production is 66.1 BSCF and a recovery factor of 82.6%.
Modeling the Combined Effect of Salt Precipitation and Fines Migration on CO2 Injectivity Changes in Sandstone Formation M Nabil Ziaudin Ahamed; Muhammad Azfar Mohamed; M Aslam Md Yusof; Iqmal Irshad; Nur Asyraf Md Akhir; Noorzamzarina Sulaiman
Journal of Petroleum and Geothermal Technology Vol 2, No 2 (2021): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v2i2.5421

Abstract

Carbon dioxide, CO2 emissions have risen precipitously over the last century, wreaking havoc on the atmosphere. Carbon Capture and Sequestration (CCS) techniques are being used to inject as much CO2 as possible and meet emission reduction targets with the fewest number of wells possible for economic reasons. However, CO2 injectivity is being reduced in sandstone formations due to significant CO2-brine-rock interactions in the form of salt precipitation and fines migration. The purpose of this project is to develop a regression model using linear regression and neural networks to correlate the combined effect of fines migration and salt precipitation on CO2 injectivity as a function of injection flow rates, brine salinities, particle sizes, and particle concentrations. Statistical analysis demonstrates that the neural network model has a reliable fit of 0.9882 in R Square and could be used to accurately predict the permeability changes expected during CO2 injection in sandstones.
Gas Injection Optimization to Increase Oil Production at MRA PT. PHE ONWJ Harry Budiharjo Sulistyarso; KRT Nur Suhascaryo; Mochamad Jalal Abdul Goni
Journal of Petroleum and Geothermal Technology Vol 2, No 2 (2021): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v2i2.5519

Abstract

The MRA platform is one of the offshore platforms located in the north of the Java Sea. The MRA platform has 4 production wells, namely MRA-2ST, MRA-4ST, MRA-5, and MRA-6 wells. The 4 production wells are produced using an artificial lift in the form of a gas lift. The limited gas lift at the MRA Platform at 3.1 MMSCFD makes the production of wells at the MRA Platform not optimal because the wells in the MRA Platform are experiencing insufficient gas lift. Optimization of gas lift injection is obtained by redistribution of gas lift injection for each. The results of the analysis in this study indicate that the optimum gas lift injection for the MRA-2ST well is 0.5552 MMSCFD, the MRA-6 well is 1.0445 MMSCFD, the MRA-5 well is 0.7657 MMSCFD, finally the MRA-4ST well with gas injection. lift is 0.7346 MMSCFD. The manual gas lift in the MRA-4ST is also replaced based on an economic feasibility analysis to ensure that the gas lift injection for each well can be kept constant. The redistribution of gas lift carried out by the author has increased the total production rate of the MRA Platform by 11,160 BO/year or approximately USD 781,200/year. Keywords: Gas lift; Insufficient; Optimization

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