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All Journal JOURNAL OF EARTH ENERGY ENGINEERING Journal of Petroleum and Geothermal Technology Journal of Earth Energy Science, Engineering, and Technology Scientific Contributions Oil and Gas
Daton, Wijoyo Niti
Petroleum Engineering Department, Institut Teknologi Bandung
Chemical Engineering, Chemistry & Bioengineering Earth & Planetary Sciences Energy Engineering Materials Science & Nanotechnology

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Application of Mechanistic Modeling for Gas Lift Optimization: A General Scaling Curve for Variations of Tubing Size to Optimum Gas Injection Prasandi Abdul Aziz; Ardhi Hakim Lumban Gaol; Wijoyo Niti Daton; Steven Chandra
Journal of Earth Energy Engineering Vol. 8 No. 2 (2019): OCTOBER
Publisher : Universitas Islam Riau (UIR) Press

Show Abstract | Download Original | Original Source | Check in Google Scholar | Full PDF (2160.322 KB) | DOI: 10.25299/jeee.2019.vol8(2).3623

Abstract

Gas Lift is currently held as one of the most prominent method in artificial lift, proudly operated flawlessly in hundreds of oil wells in Indonesia. However, gas lift optimization is still governed by the exhaustive Gas Lift Performance Curves (GLPC). This practice, albeit as established as it should be, does require repetitive calculations to be able to perform in life of well operations. Therefore, a new approach is introduced based on the mechanistic modeling. This research highlights the application of fundamental mechanistic modeling and its derivative, the Flow Pattern Map (FPM) for quick estimation of optimum injection gas rate, accompanied by a novel correction factor to account changing tubing sizes. It is hoped that this approach can be beneficial in developing a multitude of gas lift wells with changing tubing sizes.
Completion Design for The Development of a Multi-Layer and Multi Fluid Reservoir Systemin Offshore Well AA-01, North-West Java Wijoyo Niti Daton; Vincent Chandra; Steven Chandra
Journal of Earth Energy Engineering Vol. 10 No. 2 (2021)
Publisher : Universitas Islam Riau (UIR) Press

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25299/jeee.2021.6606

Abstract

Completion systems are important components of hydrocarbon field development. As the link between the reservoir and surface facilities, completions need to be designed to maximize hydrocarbon recovery and withstand consistently changing conditions for years, within the safety requirements. However, designing completion for a well comprising a multi-layer and multi-fluid reservoir is quite challenging. The completion design must use the right materials and be able to safely produce single, as well as commingle products, and add any artificial lifts, depending on the method with the most optimum value. This paper, therefore, discusses the model development of completion design for an offshore well AA-01, one of the offshore wells with multi-layer and multi-fluid reservoir systems in Indonesia. Well AA-01 penetrates two productive layers, the upper layer AA-U1, and the lower layer AA-L2. The upper layer is a gas reservoir with initial gas in place of 1440 MMSCF, while the lower layer is an oil reservoir with initial oil in place of 6.1 MMSTB. In addition, the model design used available field data, for instance, PVT and DST, from well X. The base well completion was also used to model the completion design in software. Meanwhile, commercial software was utilized to estimate the well hydrocarbon recovery. Subsequently, several designs were tested, and the design with maximum production as well as hydrocarbon recovery was selected. The completion design selected comprises 9⅝ inch 47 ppf L-80 production casing, as well as 7⅝ inch 29.7 ppf L-80 liner, and produced commingle with oil and gas recovery of about 50.16% and 92.3%, respectively, in 5 years production
Integrated Completion Study for Hpht Sour Gas Well Development in Carbonate Reservoir X Steven Chandra; Wijoyo Niti Daton; Ellen Setiawan
Journal of Earth Energy Engineering Vol. 11 No. 1 (2022)
Publisher : Universitas Islam Riau (UIR) Press

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.25299/jeee.2022.7133

Abstract

The increasing need for energy sources and the decreasing available reserves have promoted oil and gas companies to explore and manage marginal reservoirs, such as the sour gaseous environment. This is to maintain the balance of energy supply and demand. Due to the supply of Natuna Gas Field, the gap in gas supply-demand is likely to decrease by 20%, as regards the example of a potential sour gaseous environment (Batubara, 2015). Therefore, the immediate development of this potential source is very relevant. The sour field approximately shares 40% of Indonesia’s total gas reserve with 75% recovery, at an estimated OGIP of 222 TSCF. However, this environment is economically unproductive due to having high carbon dioxide (CO2) and hydrogen sulfide (H2S) contents, which are toxic and corrosive. Based on previous studies, the X-reserves reportedly contained 32% CO2 and 7072 ppm H2S, with fluid gravity of 42 API. This discretionary source of CO2 was recently brought into production from a well with a depth of 8400 ft, perforated at a limited interval of 7100 to 7700 ft. The harsh environment presented many challenges to the completion of the design, as well as the need to incorporate corrosion effects with unique equipment and material selection for the tubular structure. Therefore, this study aims to determine reservoir fluids and production performance, as well as also predict the corrosivity of dissolved CO2 in the natural gas. With the simulation and prediction, the proper material and equipment selection was obtained, based on the required sour service. The results showed that the wet gas reservoir of the X-field produced an optimum rate of 19.1063 MMSCFD. For the completion of the design, Nickel Alloy SM2535 or SM2242 was needed, due to damages in form of corrosion and pitting
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.
Application of Flow Pattern Map for Solving Liquid Loading Problems in Well AA Steven Chandra; Wijoyo Niti Daton; Johannes Marcel Susilo
Journal of Earth Energy Science, Engineering, and Technology Vol. 5 No. 1 (2022): JEESET VOL. 5 NO. 1 2022
Publisher : Penerbitan Universitas Trisakti

Show Abstract | Download Original | Original Source | Check in Google Scholar | Full PDF (694.011 KB) | DOI: 10.25105/jeeset.v5i1.10004

Abstract

About two-thirds of fields that exist in the world right now are classified as mature fields. Mature fields usually have a lot of problems that occurred during production. Mature field is classified as field which has produced as much as fifty percent of their established proved plus probable resources estimation or has produced for more than twenty-five years. Empowerment of mature well can be increasing the efficiency of well productivity. Productivity decline can be caused by low maintenance of flow pattern in a well. The other problems which commonly happen is decreasing of reservoir pressure of the well, liquid loading, slugging, and high water cut percentage. Several methods can be used to solve a lot of problems in mature well. The methods can be applied to get an optimum well productivity result. This study shows that Well AA has a slug flow pattern using matching method on a flow pattern diagram. Gas injection and velocity string are applied to solve the problems for Well AA. Gas rate of about 12 MMSCFD is obtained with gas injection method to get annular flow pattern and three different sizes of velocity string are used which are 1.25 inch, 1.5 inch, and 2.0625 inch with churn flow pattern. It is identified that the use of velocity string of 1.25 inch is the optimum method for Well AA.
New Perspective to Unlock the Potential of Lenses Gas Reservoir in Indonesia Using Integrated Reservoir-Production System Wijoyo Niti Daton; Steven Chandra; Nathania Jessica
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.v4i2.9352

Abstract

The potential of lenses gas reservoirs has become an interesting target in meeting energy needs in Indonesia. As the next energy backbone in Indonesia, the most suitable strategy needs to be developed for maintaining productivity and maximizing gas recovery. Developing gas reservoir can be challenging due to several reservoir and fluid characteristics. The development strategy must use a special production scenario and an optimized completion design.This paper discusses the process of development strategy determination for lenses gas reservoir by using commercial software. The lenses gas reservoir consists of four interest zones which penetrated by one offshore well. Each interest zone has different reserve and deliverability.The available data used are PVT, petrophysics, tubing diameter, and production parameters. By inputting these data into the software, the well recovery can be estimated. Various production scenarios are tested until a scenario is selected as the suitable production method. The production method selected is commingled using scenario 1, which to produce all lenses together with considering plateau rate 15 MMSCFD for 10 years production. Referring to the suitable production method, optimized completion designs are also selected (wellhead pressure and tubing diameter). The wellhead pressure selected is 150 psig, while the tubing diameter selected is 4.5-inch.
NANO-SURFACTANT HUFF AND PUFF OPTIMATIZATION IN MARGINAL X FIELD USING COMMERCIAL SIMULATOR Ariel Paramastya; Steven Chandra; Wijoyo Niti Daton; Sudjati Rachmat
Scientific Contributions Oil and Gas Vol 42 No 2 (2019)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/SCOG.42.2.375

Abstract

Economic optimization of an oil and gas project is an obligation that has to be done to increase overall profi t, whether the fi eld is still economically feas ible or the fi eld has surpassed its economic limit. In this case, a marginal fi eld waschosen for the study. In this marginal fi eld EOR methods have been used to boost the production rate. However, a full scale EOR method might not be profi table due to the amount of resources that is required to do it. Alternatively, Huff and Puff method is an EOR technique that is reasonable in the scope of single well. The Huff and Puff method is an EOR method where a single well serves as both a producer and an injector. The technique of Huff and Puff: (1) The well isinjected with designed injection fl uid, (2) the well is shut to let the fl uid to “soak” in the reservoir for some time, and (3) the well is opened and reservoir fl uids are allowed to be produced. The injection fl uid (in this case, nano surfactant) is hypothesized to reduce interfacial tension between the oil and rock, thus improving the oil recovery. In this study, the application of Huff and Puff method using Nanoparticles (NPs) as the injected fl uid, as a method of improving oil recovery is presented in a case study of a fi eld in South Sumatra. The study resulted that said method yields an optimum Incremental Oil Production (IOP) in which the economic aspect gain more profi t, and therefore it is considered feasible to be applied in the fi eld.
Well Integrity Study for CO2 WAG Application in Mature Field X, South Sumatra Area for the Fulfillment as CO2 Sequestration Sink Steven Chandra; Prasandi A Aziz; Muhammad Raykhan Naufal; Wijoyo Niti Daton
Scientific Contributions Oil and Gas Vol 44 No 2 (2021)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/SCOG.44.2.587

Abstract

The most of today's global oil production comes from mature fields. Oil companies and governments are both concerned about increasing oil recovery from aging resources. To maintain oil production, the mature field must apply the Enhanced Oil Recovery method.  water-alternating-gas (WAG) injection is an enhanced oil recovery method designed to improve sweep efficiency during  injection with the injected water to control the mobility of . This study will discuss possible corrosion during  and water injection and the casing load calculation along with the production tubing during the injection phase. The following study also performed a suitable material selection for the best performance injection. This research was conducted by evaluating casing integrity for simulate  water-alternating-gas (WAG) to be applied in the X-well in the Y-field, South Sumatra, Indonesia. Corrosion prediction were performed using Electronic Corrosion Engineer (ECE®) corrosion model and for the strength of tubing which included burst, collapse, and tension of production casing was assessed using Microsoft Excel. This study concluded that for the casing load calculation results in 600 psi of burst pressure, collapse pressure of 2,555.64 psi, and tension of 190,528 lbf. All of these results are still following the K-55 production casing rating. While injecting , the maximum corrosion rate occurs. It has a maximum corrosion rate of 2.02 mm/year and a minimum corrosion rate of 0.36 mm/year. With this value, it is above NORSOK Standard M-001 which is 2 mm/year and needs to be evaluated to prevent the rate to remain stable and not decrease in the following years. To prevent the effect of maximum corrosion rate, the casing material must use a SM13CR (Martensitic Stainless Steel) which is not sour service material.
Tubing Strength Evaluation and Failure Assessment for Reactivation of Well PDD-2 as Steam Injector Well Steven Chandra; Wijoyo Niti Daton; Mohammad Hafidz Setiawan
Scientific Contributions Oil and Gas Vol 44 No 3 (2021)
Publisher : Testing Center for Oil and Gas LEMIGAS

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.29017/SCOG.44.3.712

Abstract

Many old oil wells still exist in Indonesia, some of those wells has been shut in due to several reasons, two of those reasons are: the oil production that declines significantly and weak well integrity so that the well cannot withstand obstructions that occur during production. To maintain and boost Indonesia's oil production, Enhanced Oil Recovery (EOR) methods can be applied in mature fields. One of EOR methods that has the most extensive application is steam flooding, in which the fluid is injected continuously to drive the oil from injector to producer. This EOR method is a successful method to increase heavy-oil production.The application of steam flooding, most notably in older wells presents itself with possible well integrity problem. Steam flooding well has a very high risk of casing and tubing failure that caused by the loads from burst, collapse, tension, and thermal effect due to the high temperature steam that can decrease the rating of casing or tubing. Hence, this study focuses on evaluating tubing's strength on the existing well whether the tubing is applicable for steam flooding or must be replaced. In this study, a tubing strength evaluation of well PDD-2 for steam flooding method will be discussed. Tubing strength evaluation consists of two stage. The first stage is evaluation due to burst, collapse, and tension loads and the other stage is evaluation due to thermal effects of injected steam. Well PDD-2 has K-55 tubing with 3.5 inch OD, burst rating of 7,947.5 psi, collapse rating of 7,052.9 psi, and tension rating of 160,262 Ibf. Based on the evaluation result, this existing K-55 tubing still be able to withstand the loads from burst, collapse, tension, and thermal effects. Hence, the reactivation of Well PDD-2 as steam injector well can be done without replacing or upgrading the tubing.
Co-Authors Ardhi Hakim Lumban Gaol Ariel Paramastya Aziz, Prasandi A Brian Tony Chandra, Steven Ellen Setiawan Johannes Marcel Susilo Mohammad Hafidz Setiawan Mohammad Rachmat Muhammad Raykhan Naufal Muhammad Rizki Amrullah Nathania Jessica Naufal, Muhammad Raykhan Paramastya, Ariel Prasandi A Aziz Prasandi Abdul Aziz Prasandi Abdul Aziz Prasandi Abdul Aziz Rachmat, Sudjati Setiawan, Mohammad Hafidz Steven Chandra Steven Chandra Steven Chandra Steven Chandra Steven Chandra, Sudjati Rachmat Vincent Chandra