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All Journal Journal of Geoscience, Engineering, Environment, and Technology Journal of Earth Energy Science, Engineering, and Technology
Budi, Iwan Setya
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Earth & Planetary Sciences Energy Engineering Environmental Science Physics

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Field Development with Scenario Reactivation of Non-Active Zones Through Reservoir Simulation: A Case Study of The Kappa Offshore Field, West Natuna Budi, Iwan Setya; Sumolang, Christianov Agassi Batistuta
Journal of Geoscience, Engineering, Environment, and Technology Vol. 8 No. 02-2 (2023): Special Issue from The 1st International Conference on Upstream Energy Techn
Publisher : UIR PRESS

Show Abstract | Download Original | Original Source | Check in Google Scholar

Abstract

This research provides the scenario of a field development plant with the primary goal of acknowledging the reservoir model of Kappa Field in determining the optimum field development scenario to increase the recovery factor. In this research, field development will be carried out by creating scenarios that differentiate certain parameters to see the differences from these scenarios. The main problem in this field is to find out the feasibility of a field that has a history of production from 1986 to 2022 or for 33 years. In addition, the main objective of this research is to determine the reservoir driving mechanism of the Pasir RH-7 layer and determine the best field development scenario to optimize production in the Kappa field. The method used in this study is the reservoir modeling method using production data and reservoir data that has been obtained from the company and then managed using the Petrel Software assisted by Eclipse and MatBal. Before developing field development scenarios, an analysis is carried out using several different methods, including analysis with the decline curve analysis method in determining the remaining recoverable reserves as the validation of Kappa Field's feasibility, identify the driving mechanism of the reservoir, and history matching between history production data with simulation results. Sensitivity analysis of the field development is also conducted through various scenarios, including adding or adjusting well perforation interval, infill well adding, five water injection wells, and four gas injection wells. Other than that, injection gas and water rates in injection wells are also being exercised during the sensitivity analysis. Simulation results show the best scenario of Kappa Field is ten infill wells and four injection wells with a water injection rate of 1000 BWPD and gas injection rate of 1 MMSCF/d, giving the optimum recovery factor result of 39.33% from oil reserves. The results of this research will have a positive impact on the development of the Kappa field in order to increase production from fields that have been producing since 1986 and stopped production in 2019.
Numerical Simulation of Solvent Injection for Late-stage Steamflood Budi, Iwan Setya
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/b1x18s28

Abstract

This paper evaluates the solvent injection process to recover remaining oil during late-stage of a steamflood using numerical simulation. After Steam Break through, a steamflood recovery will enter a late period identified by increasing Steam-Oil Ratio (SOR). It reduces the economics since steam is an intensive energy process aiming to recover oil quickly, much quicker than chemical EOR. Solvent is expected to substitute a large amount of steam injection and able to lower heavy oil viscosity.  In oilfield worldwide, solvent is often used as an alternative for SAGD where well configuration is uniquely arranged using a pair of horizontal wells as injector and producer. However, instead of horizontal well pair as in SAGD, this study examines common pattern (inverted 9 spot) in steamflood project which mainly utilizes vertical wells for both injector and producer. Using thermal methods, the fluid production favorably tends to be higher, but heat loss associated from surface line down to subsurface can hurt the economics. Three scenarios are developed and studies resulting that oil recoveries achieved are not signifacntly lower however at the same time requires much lower energies (and cost) for solvent injection.
Evaluation of Gas Lift Deepening Design Using a Retrofit Gas Lift System to Increase Well Production in an Offshore Field: Case Study of Well S-7 Suhartanto, Surya Arif Wibowo; Budi, Iwan Setya; Damargalih, Yono
Journal of Geoscience, Engineering, Environment, and Technology Special Issue from The 2nd International Conference on Upstream Energy Technology and Digitalization
Publisher : UIR PRESS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25299/jgeet.2025.10.1.1.24189

Abstract

S-7 well is a horizontal well in the NDF Field that produces hydrocarbons from carbonate formation for over seven years using gas lift. Over time, S-7 well has experienced a significant decline in production due to reservoir pressure along with an increase in water cut. To address this issue, a well intervention was conducted to deepen the injection point by installing Retrofit Gas Lift technology, aiming to enhance the well's production to an optimal level. This research focuses on evaluating the application of Gas Lift Deepening using Retrofit Gas Lift (RGL) in Well S-7 through well modeling methods with PROSPER software and providing recommendations for an optimal Gas Lift Deepening design. The study analyzes well modeling for Well S-7 before and after RGL installation, validated using well test data to compare production performance in both scenarios. The evaluation proceeds by identifying the parameters that influence the effectiveness of the Retrofit Gas Lift (RGL), followed by designing an optimized RGL system to enhance production performance. Based on the research, the installation of the Retrofit Gas Lift (RGL) in Well S-7 resulted in an increase in the production rate of 78.58 STB/d. Sensitivity testing identified key factors influencing the production rate, including reservoir pressure, top node pressure, gas injection rate, coil tubing size, and coil tubing length. Design optimization by adjusting the top node pressure to 130 psi, coiled tubing length to 2000 ft, coiled tubing size to 1.75 in, and gas lift injection rate to 1 MMSCFD resulted in an increased flow rate of 220.86 STB/d and a drawdown of 751.77 psi.
Evaluation of Gas Lift Deepening Design Using a Retrofit Gas Lift System to Increase Well Production in an Offshore Field: Case Study of Well S-7 Suhartanto, Surya Arif Wibowo; Budi, Iwan Setya; Damargalih, Yono
Journal of Geoscience, Engineering, Environment, and Technology Special Issue from The 2nd International Conference on Upstream Energy Technology and Digitalization
Publisher : UIR PRESS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25299/jgeet.2025.10.1.1.24189

Abstract

S-7 well is a horizontal well in the NDF Field that produces hydrocarbons from carbonate formation for over seven years using gas lift. Over time, S-7 well has experienced a significant decline in production due to reservoir pressure along with an increase in water cut. To address this issue, a well intervention was conducted to deepen the injection point by installing Retrofit Gas Lift technology, aiming to enhance the well's production to an optimal level. This research focuses on evaluating the application of Gas Lift Deepening using Retrofit Gas Lift (RGL) in Well S-7 through well modeling methods with PROSPER software and providing recommendations for an optimal Gas Lift Deepening design. The study analyzes well modeling for Well S-7 before and after RGL installation, validated using well test data to compare production performance in both scenarios. The evaluation proceeds by identifying the parameters that influence the effectiveness of the Retrofit Gas Lift (RGL), followed by designing an optimized RGL system to enhance production performance. Based on the research, the installation of the Retrofit Gas Lift (RGL) in Well S-7 resulted in an increase in the production rate of 78.58 STB/d. Sensitivity testing identified key factors influencing the production rate, including reservoir pressure, top node pressure, gas injection rate, coil tubing size, and coil tubing length. Design optimization by adjusting the top node pressure to 130 psi, coiled tubing length to 2000 ft, coiled tubing size to 1.75 in, and gas lift injection rate to 1 MMSCFD resulted in an increased flow rate of 220.86 STB/d and a drawdown of 751.77 psi.
Co-Authors Damargalih, Yono Suhartanto, Surya Arif Wibowo Sumolang, Christianov Agassi Batistuta