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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 8 Documents
 1 
Search results for , issue "Vol. 6 No. 2 (2025): November" : 8 Documents clear
Sucker Rod Pump Design using Petroleum Engineering Application– PEARL 4.0 as a Breakthrough Solution in Digitalization (Study Case PWP-13) at Limau Field, Pertamina Hulu Rokan, South Sumatra, Indonesia Putra, Panca Wibawa; Suranto, Suranto; Kristanto, Dedi
Journal of Petroleum and Geothermal Technology Vol. 6 No. 2 (2025): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v6i2.13935

Abstract

PT. Pertamina Limau Field in South Sumatra, producing 4,113 BOPD and 10.69 MMSCFD from 11 structures, have a significant low production issue with well PWP-13. Although the well produces 40 BOPD, frequent failures in the sucker rod pump (SRP) system cause excessive downtime and low production, reaching 4,505 barrels oil (BO) in 2023. This research aimed to optimize PWP-13 production by redesigning the SRP system, applying API RP 11 L standards to improve the pump’s reliability. Build new calculation, The Petroleum Engineering Application (PEARL 4.0) integrated variables such as taper rod arrangement and sucker rod type. This PEARL 4.0 was then applied to well PWP-13 with Rig Service. Monitoring results indicated a production increase to 90 BOPD, with average incremental production reaching 60 BOPD, supported by extended operational lifetime. Financial analysis showed a high net present value (NPV) of 693 MUSD, internal rate of return (IRR) of 498%, and a payback period (POT) of 0.189 years, confirming a rapid return on investment (ROI) 8.6. The SRP redesign offers a sustainable solution for sucker rod failures, enhancing production efficiency and profitability for company. Keywords: artificial lift, sucker rod pump design, petroleum engineering application
Hitting the Jackpot: Reaching up to 10000 BBL through Simson Idle Well Reactivation Strategy Purnomo, Simson; Kristanto, Dedi; Suhascaryo, Nur
Journal of Petroleum and Geothermal Technology Vol. 6 No. 2 (2025): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v6i2.14188

Abstract

This study seeks the effective reactivation strategy of the Simson idle well in the Purnomo oilfield PT Pertamina EP Cepu to produce free-emulsion oil with low costs and technical risks. DCA and Pipesim were used to calculate the production forecast, the precise choke, and the flow coefficient. Due to its remote location, a rig-less and naturally flowing well minimized the cost. A modified choke manifold compliant with the API 6A was installed to control the flow rate from the annulus to the Tank on Site (TOS). The cumulative production in 2023 reached 10.961 bbl with the average BSW at 2%. To avoid water coning, the well should be operated under the critical rate of 60 BFPD.  To maintain stable production, the optimum flow coefficient was Cd 0.838 by installing the first 5-mm choke and the second 8.7-mm choke. The average daily production rate by intermittent flow i.e. of 5-hour production and 19-hour shut-in well was 34 blpd, 33 bopd with water cut at 1.64%. By the end of the PSC contract in 2035, the production forecast value using the choke manifold can reach 81 MSTB – 50 MSTB higher than the SRP method. Keywords: idle well reactivation, flow coefficient, choke manifold
Chemical Enhanced Oil Recovery (CEOR) Injection Planning to Obtain the Optimum Development Scenario: A Case Study in TBG Field Aliefan, Tubagus Adam; Kristanto, Dedi; Swadesi, Boni
Journal of Petroleum and Geothermal Technology Vol. 6 No. 2 (2025): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v6i2.14218

Abstract

Chemical Enhanced Oil Recovery (CEOR), particularly through the use of surfactant and polymer injection, has emerged as one of the most effective tertiary recovery techniques for increasing oil recovery from mature reservoirs. CEOR enhances volumetric and microscopic sweeping efficiency, improving the overall recovery factor (RF). This study focuses on Zone C of the TBG Field, a mature oil field with a current recovery factor below 25%, highlighting its potential for further optimization through CEOR. The field, which began production in 1961 and introduced peripheral water injection in 1995, remains a key candidate for unlocking remaining oil in place. This research integrates primary data, including core analysis, PVT data, and polymer field trial results, with secondary data such as petrophysical properties and production performance. Using dynamic modeling with CMG software, the study evaluates three CEOR injection scenarios to determine the most effective method for improving oil recovery. The scenarios simulated included Baseline Waterflood + Polymer (0.4 PV) and Baseline Waterflood + (Surfactant + Polymer) + (Polymer) (0.2 PV SP + 0.7 PV P). The optimal scenario, involving Baseline Waterflood + (Surfactant + Polymer) + (Polymer), demonstrated an incremental oil recovery of 1.24 MMSTB and a recovery factor improvement of 0.974%. The novelty of this research lies in its integration of polymer field trial data with innovative surfactant-polymer combinations tailored specifically to Zone C's reservoir characteristics. This approach provides a scientifically robust and practical strategy for enhancing oil recovery in challenging reservoir conditions. The study concludes that CEOR is a viable method for mature fields like TBG, offering significant potential for improved oil recovery. Future recommendations include exploring the economic feasibility of the selected injection scenario and ensuring the readiness of surface facilities to support full-scale implementation.
A Comparative Cost Estimation of Plug and Abandonment Well Using SNI 13-6910-2002 and NORSOK Standard D-010 Regulations: A Case Study in the H-11 Well of Colibri Field Yusgiantoro, Luky A.; Kristanto, Dedi; Hariyadi, Hariyadi; Stephanie, Vania Raina; Irawan , Gondo
Journal of Petroleum and Geothermal Technology Vol. 6 No. 2 (2025): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v6i2.14731

Abstract

This research discusses the comparative determination of appropriate method for plug and abandonment (P&A) activities in directional wells, and finding an economical cost between SNI 13-6910-2002 and NORSOK Standard D-010 regulations. Colibri field consists of several wells, including H-11 well which is a directional well, where the well was used as a reference for determination in implementation of plug and abandonment activities after the well condition has reached the economic limit. Plug and abandonment (P&A) activities in the Colibri field was implemented with designing a work plan to determine the section for the zone to be plugged by calculating the volume of cement, additives, and completion fluid, using the rig method. The result of the research is to determine the estimation costs that need to be prepared to implement well abandoned activities according to the closing year using SNI 13-6910-2002 and NORSOK Standard D-010 regulations. The cost estimation result of H-11 well using SNI 13-6910-2002 is 417,630.25 USD, while for NORSOK Standard D-010 is 813,315.77 USD. Therefore, based on the cost estimation results, the proposed method chosen for cost estimation of plug and abandoned of H-11 well in Colibri Field is SNI 13-6910-2002 regulation.
Evaluation of Drill Bits Use in KRS-09 Well, Kuarsa Field Based on Well Log Data, XRD Testing and MBT From Drill Cuttings Alfatah, Faritsi Luqman; Buntoro, Aris; Swadesi, Boni; Hartoyo, Puji; Putradianto, Ristiyan Ragil
Journal of Petroleum and Geothermal Technology Vol. 6 No. 2 (2025): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v6i2.14876

Abstract

The use of drill bits in well drilling is very important to break and penetrate rocks. The selection of drill bits is usually done by testing drill bits from previous wells that have similar static rock mechanical parameters, but this method is time consuming and expensive because the core must be analyzed in the laboratory. As an alternative, the selection of drill bits is evaluated using logging data as an approach to calculating the Unconfined Compressive Strength (UCS) value whose accuracy is improved by integrated the brittleness index through X-Ray Diffraction (XRD) analysis and Mechanical Specific Energy (MSE) parameter to assess how efficiently drilling is performed. The obtained parameter data is then calculated for correlation using Pearson correlation. Integration of rock mechanical (UCS, BI, MSE) and mineralogy has proven to be more effective in selecting drill bits than experience-based methods. Therefore, drilling planning should consider rock strength, deformation properties, and mineral composition to improve drill bit efficiency and life.
Evaluation of HPU Performance in High GLR Oil Well BNG-X3 Benuang Field South Sumatera Pramana, Edho; Suranto; Helmy, Mia Ferian; Bintarto, Bambang; Rahmadhini, RR Rahajeng Suryo; Wicaksono, Dimas Suryo
Journal of Petroleum and Geothermal Technology Vol. 6 No. 2 (2025): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v6i2.14921

Abstract

Nowadays, producing BNG-X3, a well in Benuang Field, is relatively easy due to its natural drive which is bottom water aquifer combined with high associated gas content. Hence, most of the wells are flowing naturally from reservoir to surface facilities. However, issues most likely to occur overtime, especially when the pressure depletes due to production hence could not supply enough energy for the fluid to flow naturally. In this study, analysis was conducted to address this future problem by implementing a suitable artificial lift for this kind of circumstances. To get a more sustainable and continuous result, post installation evaluation was carried out to define key parameters that can lead to success and optimization in future application of Hydraulic Pumping Unit (HPU) in Benuang Field. The analysis consists of reserve calculations, economic feasibility, and step by step design for artificial lift HPU. The HPU installation and production performance monitoring for well BNG-X3 were conducted thoroughly to assess whether the implementation was optimized based on the well’s potential. Reserve calculations were performed using the Decline Curve Analysis (DCA) method and Pipesim software, while the HPU design was developed using Microsoft Excel. Field data was utilized for monitoring and evaluating the results. Based on the analysis, well BNG-X3 still holds significant potential. From an economic perspective, it has a positive Net Present Value (NPV) of $615,000 and a Payback Period (POT) of less than one year. Production observations indicate that well BNG-X3, with a Gas-Liquid Ratio (GLR) of up to 1000 SCF/STB and a high gas production rate, can be reactivated. The use of a 2.5” pump, along with SPM 5 and SL 155-inch parameters, has been fairly successful in restoring lost production. However, the achieved production rate has not yet reached the well's optimal potential due to the pump efficiency still being below the target (67%).
Re-Design of ESP Pump in EHS-155 Well in Tanjung Field Based on Problematic Scale and Economic Analysis Hesmatiar, Ekwal; Herianto, Herianto; Budiharjo, Harry
Journal of Petroleum and Geothermal Technology Vol. 6 No. 2 (2025): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v6i2.16090

Abstract

The repair of Electric Submersible Pump (ESP) in well X-155 at the Tanjung Field has become a major issue impacting production rates and increasing operational costs. In 2024, well X-155 experienced 7 well service interventions due to pump failures, which caused damage to the pump impeller and resulted in a loss of oil production. This failure was identified as being caused by the deposition of carbonate minerals (scale), which became the primary cause of damage to the ESP pump. To confirm the presence of scale, solid scale deposition was analyzed using X-ray Diffraction (XRD) methods in an independent laboratory, along with fluid property testing. This method was used to determine the composition and crystalline phases of the scale formed in the well. This study aims to analyze the causes of scale formation in the ESP system. It is expected that the findings from this research will provide solutions to pump failures, reduce the frequency of such failures, and improve operational efficiency at the Tanjung Field, particularly through the implementation of scale inhibitor treatments. The scale treatment for well X-155 is unique due to the need to formulate a scale inhibitor that can function effectively under the high-temperature and high-pressure conditions present in the well
Waterflood and Polymer Injection Design for New Target Reservoir based on Injection Pattern Optimization, Injection Rate Sensitivity, and Injection Pressure Sensitivity Fransiscus Asisi Lugas Ariobimo; Swadesi, Boni; Suhascaryo, Nur
Journal of Petroleum and Geothermal Technology Vol. 6 No. 2 (2025): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v6i2.16337

Abstract

Field “X” is in Tabalong Regency, South Kalimantan, and is operated by Pertamina Hulu Indonesia Zona 9. The peak primary production occurred in March 1963, reaching 47,963 BOPD. Full-scale waterflood implementation with a staggered line-drive injection pattern began in January 1995, and the peak secondary production occurred in January 1999 at 10,095 BOPD. This study was conducted using a dynamic model that had undergone initialization validation and history matching. The assessment of polymer injection pattern candidates was carried out through a screening stage based on screening criteria and reservoir property analysis to determine patterns that could be prioritized as pilot areas for an optimal polymer injection scenario in Zone B. Pattern analysis criteria were based on movable remaining oil saturation, movable remaining oil in place, pattern area, and average transmissibility, evaluated for the Zone B reservoir under post-waterflood conditions. Sensitivity analyses on water injection rate and injection pressure were then performed to obtain the optimum waterflood injection scenario. After optimizing the injection pattern and determining the optimum waterflood injection scenario, polymer input parameters were applied to the model, followed by sensitivity analyses on polymer injection rate and pressure to obtain the optimum polymer injection scenario for Zone “B” of Field “X By the end of the production forecast in January 2066, the optimum waterflood injection scenario at the end of the production forecast provides an incremental oil gain of 1.5 MMSTB with an incremental recovery factor of 2.19% relative to OOIP, while the combination of optimum waterflood and polymer injection at the end of the production forecast provides an incremental oil gain of 2.14 MMSTB with an incremental recovery factor of 3.13% relative to OOIP; demonstrating improved sweep efficiency, oil bank formation, and effective mobilization of residual oil across Zone B.

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