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INDONESIA
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 87 Documents
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Evaluation of the Hydraulic Fracturing Implementation at Well WEA-01 Layer A3 Edgie Yuda Kaesti; Suwardi Suwardi; Ratna Widyaningsih; Muhammad Zakiy Yusrizal; Wijaya Ananditya Rifqi; Puji Hartoyo
Journal of Petroleum and Geothermal Technology Vol 4, No 2 (2023): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i2.9834

Abstract

The WEA-01 well produces in the A3 productive layer, talangakar formation with a layer thickness of 32.80 ft with a perforation interval of 4340.55 – 4360.24 ftMD where from petrophysical data this formation is dominated by sandstone with a permeability of 3 mD which is classified as low and a tight formation (Koesoemadinata, 1980) with 10% porosity. This is the basis for the stimulation of Hydraulic Fracturing. Hydraulic fracturing that has been implemented needs to be evaluated to find out whether the implementation has been carried out optimally or not.The method to be used in the evaluation of the WEA-01 Well hydraulic fracturing implementation includes data collection, then manual calculations and evaluation with actual data. The first evaluation was to calculate the geometry of the fracture using the 2D PKN method, the second evaluation was to calculate the price increase in the productivity index using the Cinco-ley Samaniego and Dominique method and the third evaluation was to analyze the IPR curve (Inflow Performance Relationship) before fracturing using the Darcy method and after fracturing using the Pudjo Sukarno method.Based on the results of manual fracture geometry calculations using the 2D PKN method, the results obtained are fracture length (Xf) of 200.07 ft, fracture height (hf) of 32.80 ft, and fracture width (wf) of 0.23 inch, fracture conductivity of 5094.70 mD-ft, and FCD 8.5, while the results of calculating the average permeability of formations using the Howard & Fast method obtained permeability after Hydraulic Fracturing of 15.71 mD or an increase of 5.2 times from the initial conditions and calculating the productivity index using the Cinco-Ley, Samaniego & Dominique method obtained an increase in PI prices of 3.45 times and from the determination of the IPR curve, the results obtained from the comparison of the IPR curve showed an increase in the production rate from 45.00 BOPD to 330 BOPD. Based on the increase in the fluid production rate, the implementation of Hydraulic Fracturing that has been carried out can be said to be successful.Keywords – hydraulic fracturing, fracturing fluid, proppant, fracture geometry, permeability, conductivity
The Selection of Optimal Gas Production Rate using Dynamic Reservoir Simulation in Field X Rahmad Laksamana Pratama; Gerry Sasanti Nirmala; Edi Untoro; Jatmianto Jayeng Sugiantoro; Muhammad Ghazian R.A
Journal of Petroleum and Geothermal Technology Vol 5, No 1 (2024): May
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v5i1.11084

Abstract

Indonesian government has targeted a gas production rate of 12 BSCFD by 2030 to balance the energy demands and the carbon emission reduction. To achieve this goal, a comprehensive evaluation of a gas field will be carried out regarding Recovery Factor, Stable Production Period (Plateau Time), Total Production Period, and Profits using simulation programme. Dynamic Reservoir Simulation is an integrated field development simulation that combines physics, mathematics, reservoir engineering, and computer programming to analyze and predict the wells performance or how fluid flows through reservoir rocks to the surface over time under various operating conditions. There are stages in the simulation include Reservoir Model Creation, Initialization, History Matching, and Production Performance Forecasting. This research is a continuation of static reservoir modeling research done by LEMIGAS, which started by reinitializing the model and ended by forecasting the production performance of field X using several gas production flowrate scenarios to find out the optimal gas production flowrate for Field X in ten years period. The simulation result showed that the best gas production flowrate for a ten-year period is 3 mmscfd. It gives 78,505% recovery factors, with cumulative profit of $40,915,872 USD over a plateau period of 6.6 years.
Improving Gas Recovery of Water Drive Gas Reservoir Marmora Titi Malinda; Sutopo Sutopo; Muhammad Taufiq Fathaddin
Journal of Petroleum and Geothermal Technology Vol 4, No 2 (2023): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i2.10261

Abstract

A gas reservoir with bottom water drive has lower recovery factor compared to depletion drive gas reservoir. Along with the increase in gas demand and the majority of gas reservoirs are water-drive, a method that are still being developed to increase the recovey factor in water-drive gas reservoir is co-production method. This method reducing water influx by planned water production. In this study, a conceptual model of gas reservoir with depletion-drive and water-drive is build and being analyzed. Co-production technique is applied by adding one water production well to the water-drive gas reservoir. The recovery factor is being analyzed through some production scenarios. Sensitivity analysis are being done with parameters including: reservoir permeability, permeability anisotropy, aquifer volume, flow rate of water production, gas tubing head pressure, and gas well perforation interval Furthermore, experimental design, response surface methodology, and monte carlo simulation is used to analyze the influencing parameter of gas recovery factor. It is found from this study that co production increased gas recovery factor by 28% from water drive gas reservoir, with water production rate is the most influencing parameter.
Integrated Production Optimization of Mature Field Y Under Network Constraints Steven Chandra; Brian Tony; Rahma Widyastuti
Journal of Petroleum and Geothermal Technology Vol 4, No 2 (2023): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i2.10986

Abstract

The Y Field, a mature field experiencing declining reservoir pressure, the production of hydrocarbons is declining, leading to the need for production optimization. One crucial aspect of this optimization is the selection of suitable artificial lift methods. The choice of artificial lift methods in Field Y is dependent on the unique reservoir conditions of each well. The commonly utilized equipment for artificial lift methods in Field Y includes the Sucker Rod Pump (SRP) and the Electrical Submersible Pump (ESP).This bachelor thesis aims to develop an integrated production optimization strategy for maximizing well production in Structure X, a mature field. The study involves analyzing and optimizing artificial lift methods and integrating surface network simulation. The Inflow Performance Rate (IPR) curve is utilized to identify the production potential of each well in Structure X.By evaluating the pump performance and surface network in Structure X, it is possible to identify wells that utilize artificial lift or existing pumps and have the potential to be improved up to their maximum operating range, based on their gross flow rate (BFPD). Through optimization, adjusting the stroke per minute for the Sucker Rod Pump (SRP) and the operating frequency for the Electrical Submersible Pump (ESP) can lead to a significant increase in production. Specifically, with a design production rate of 2308.59 BFPD, an improvement of 82.23 BOPD can be achieved.
Analysis of Scale Problem Using Acidizing Stimulation in Field Z Kalrez Petroleum (Seram) LTD Sumina Idrus
Journal of Petroleum and Geothermal Technology Vol 5, No 1 (2024): May
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v5i1.11085

Abstract

The annual decrease in production at well Z occurs due to scale deposits that impede fluid flow. Scale is a production problem due to the mixing of two types of water with different properties so that the solubility limit of the compound in the formation water is exceeded. To overcome the scale, stimulation is carried out with an acidizing method using a type of acid (HCL 10%). Evaluation was conducted to determine the effect of acidizing stimulation on scale based on productivity index (PI), inflow performance relationship (IPR) curve and comparison of stimulation methods. Evaluation of test results after acidizing stimulation of well Z experienced an increase in production. Productivity Index increased from 4.748 bbl/psi to 9.036 bbl/psi. Based on the IPR curve before acidizing, the maximum flow rate (Q max) = 324,107 bpd, increased to Qmax = 769,021 bpd.Keywords: Cost Benefit, Productivity Index, Scale, Acidizing Stimulation
Improving Well Productivity through the Combination of Deep Penetrating Perforation and High Energy Gas Fracturing Techniques Fanata Yudha Nugraha; Brian Tony; Damar Nandiwardhana; Angelica Catharine Zefanya; Nur Ilham Tarsila
Journal of Petroleum and Geothermal Technology Vol 4, No 2 (2023): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i2.10814

Abstract

Perforation operations often result in formation damage and compacted zones, which can increase skin effect and decrease well productivity. To address these issues, a combination of deep penetrating perforation and high energy gas fracturing techniques can potentially solve these problems. This study utilized commercial software to simulate perforation and fracture geometry, and evaluated productivity using parameters such as skin effect, productivity index, and inflow performance relationships. Results showed that the combination technique increased productivity by 3.34 times compared to conventional perforation and 2.45 times compared to standalone deep penetrating perforation. This suggests that the combination technique effectively improves well productivity by reducing skin effect and increasing productivity index and flow rate. Overall, the study provides promising evidence for the effectiveness of the combination technique in improving well productivity.Keywords:  deep penetrating perforation; geometry; high energy gas fracturing; inflow performance relationship (IPR); productivity index (PI); skin effect
QUALITATIVE AND QUANTITATIVE ANALYSIS OF WATER CONING AND BREAKTHROUGH TIME PREDICTION ON ZNC FIELD Aqlyna Fattahanisa; Rini Setiati; Arinda Ristawati; Puri Wijayanti
Journal of Petroleum and Geothermal Technology Vol 4, No 2 (2023): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i2.10108

Abstract

Given the current public need for oil and gas as a primary energy, all oil and gas companies need to increase production to meet this demand. One of the things companies usually do to achieve this is to evaluate and analyze the productivity of each well. Of course, production decreases from time to time, so the company must try to increase its production. One of the reasons for the decline in oil production from the ZNC-1 well in the ZNC Field is the production of excessive water content. There are several factors that cause excessive water content in oil wells, and this is called water coning. The method used to determine the occurrence of the water cone problem requires qualitative and quantitative analysis. In using qualitative analysis, two analyzes were carried out, including an analysis of the production history of the well and an analysis of the Chan Diagnostic Plot showing bottom-water coning problems with late-time channeling. Meanwhile, based on the quantitative results, the critical flow rate of the ZNC-1 well calculated using the Bornazel and Jeanson method is 167 STB/D. With these results, the value of the critical flow discharge is greater than the actual discharge, which is 291.3 STB/D. Thus it can be ascertained that there has been water coning in the ZNC-1 well. After that, the breakthrough time obtained by the Bournazel and Jeanson method was 361.3 days.
Analysis of the Use of Sand Pump Control Pumps in Overcoming Sand Problem in Sucker Rod Pump (SRP) in Sp Wells In the Kawengan Field Putri Sopacua
Journal of Petroleum and Geothermal Technology Vol 5, No 1 (2024): May
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v5i1.11283

Abstract

The sand problem is a common challenge in the oil and gas industry. PT Pertamina EP Asset 4 Cepu Field in the Kawengan Field has rock which is a ngrayoung formation and the type of sandstone can cause sand to enter into the well bour when oil is produced for a long time. Therefore, we need the right tool to be able to overcome the problem of sandiness. In this case PT Pertamina EP Asset 4 Cepu Field in the Kawengan Field uses a sand control pump in an effort to overcome the sand problem. Thus, this research was conducted by analyzing the appropriate pump size from the sand rate calculation, fluid flow rate before and after using the sand control pump, as well as economic analysis. The results of the pump size analysis show that the right pump size to use is 2 joint mud anchors. The results of the subsequent analysis show an increase in the rate of fluid production after using a sand control pump. The results of the economic analysis show that the use of a sand control pump on a sucker rod pump (SRP) in the SP well is feasible because it has economic value with an oil price of 45 US$ / bbl, an NPV of 221,709 USD is obtained, and project success (IRR) reaches 106 %, as well as the value of pay out time for 1.83 years. Keywords: Economy, Flow Rate, Sand Problem, Sand Control Pump, Sand Rate.
LOW SALINITY WATER INJECTION EVALUATION AND MATURE FIELD DEVELOPMENT AT ANGGORO SHALLOW SAND, SANGASANGA FIELD Dani Novriyandi
Journal of Petroleum and Geothermal Technology Vol 5, No 1 (2024): May
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v5i1.9827

Abstract

AbstractAnggoro's shallow sand was perforated at well ANG-1033 (D4-N1 layer). Oil production in this well increased from an average of 15 BOPD to 170 BOPD. That the perforated layer was affected by low salinity water injection (salinity < 3000 ppm). Evaluation of water injection sweep efficiency was carried out using the Dykstra-Parson method, vertical efficiency of about 0.3, area efficiency of 0.7, and displacement efficiency of 0.3. The Estimated Ultimate Recovery (EUR) of this well provides is 197 MBbls with an additional RF of around 20 %. This increase is due to the low salinity water injection sweep mechanism that occurs. The clay content plays an important role in the mechanism that occurs in this layer, these mechanisms fines migration, increase in pH, multi ion exchange, double layer effect, and salting in which these mechanisms result in increased oil recovery. Seeing the production results from the D4-N1 layer and oil production in this layer can still be maximized, in the future this layer can be developed with several programs such as reactivation, workover, and development drilling.Keywords: Low salinity water injection, shallow layer, efficiency
Rock Mineralogy Analysis of Airbenakat Formation to Map the Characteristics of the Reservoir Rocks in each Depositional Environment Kharisma Idea; Taufan Marhaendrajana; I GB Eddy Sucipta; Sri Feni
Journal of Petroleum and Geothermal Technology Vol 4, No 2 (2023): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i2.10793

Abstract

The Airbenakat Formation is a sandstone reservoir which is one of the oil reservoirs located in Sumatra and is part of the South Sumatra Basin. The mineral composition of the sandstone reservoir in the Airbenakat Formation consists of quartz minerals as rock grains, clay as matrix and is often identified as cement, while carbonate as rock cement. Based on lithofacies observations, the depositional environment of the Airbenakat Formation consists of: Volcanic Alluvial Fan, Lake, Braid Bar, Braided Channel, Braid Deltaic Environment, Mud Flat, Tidal Sand Bar, Tidal Environment, Shallow Sea, and Deep Sea. This research was conducted on 2 (two) oil fields, namely MRP dan TPN which have different depositional environments but are included in the Airbenakat Formation as part of the South Sumatra Basin.The analyzes used in this study include X-Ray Diffraction (XRD) analysis, petrography, and Scanning Electron Microscopy with Energy Dispersive X-Ray Spectroscopy (SEM/EDX). Analysis of the mineralogical content of the Airbenakat Formation will assist to determine the performance of chemical injections such as injection of anionic surfactant. The anionic surfactant used for chemical injection in Airbenakat Formations will be optimal if the content of smectite and calcite minerals can be ascertained. The presence of smectite and calcite minerals will affect the results of anionic surfactant injection. This research shows the results of anionic surfactant injection on the presence of smectite and carbonate in the injected core.

Page 5 of 9 | Total Record : 87

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