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A Critical Review on Mathematical Functions Employed for Heptane Plus Characterization in Gas Condensate Reservoirs: Lessons Learned and Future Development Steven Chandra
Journal of Earth Energy Engineering Vol. 7 No. 1 (2018): APRIL
Publisher : Universitas Islam Riau (UIR) Press

Characterizing heptanes plus fraction in PVT analysis has been a complex problem since its first inception. In this publication, the author is reviewing available mathematical functions employed for this task, whilst pointing out advantages and weaknesses for each of them and proposing a new method that is capable of complex characterization. This publication addresses a new method that is capable of accurately characterize heptane plus fraction especially in discontinued areas where errors could leap up to 40%. The author modifies natural logarithmic function to be used as an accommodation to discontinuities. The modified distribution provides better accuracy in modeling the discontinuities as a straight-line function, making them ideal for real gas condensate composition characterization. The new method is tested against several test data used by previous researchers, and applied to 3 sets of field data. The results have shown that this new method is capable of lowering CPU requirement whilst making better accuracy for all test data.

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

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.

Economic Evaluation of Fiscal Regime on EOR Implementation in Indonesia: A Case Study of Low Salinity Water Injection on Field X Adityawarman Adityawarman; Faridh Afdhal Aziz; Prasandi Abdul Aziz; Purnomo Yusgiantoro; Steven Chandra
Journal of Earth Energy Engineering Vol. 9 No. 1 (2020): APRIL
Publisher : Universitas Islam Riau (UIR) Press

There are currently two fiscal regimes designated for resource allocation in Indonesia’s upstream oil and gas industry, the Production Sharing Contract Cost Recovery (PSC) and Gross Split. The Gross Split in the form of additional percentage split is designed to encourage contractors to implement Enhanced Oil Recovery (EOR) in mature fields. Low Salinity Water Injection (LSWI) is an emerging EOR technique in which the salinity of the injected water is controlled. It has been proven to be relatively cheaper and has simpler implementations than other EOR options in several countries. This study evaluates the LSWI project’s economy using PSC and Gross Split and then to be compared to conventional waterflooding (WF) project’s economy. There are four cases on Field X that are simulated using a commercial simulator for 5 years. The cases are evaluated under PSC and Gross Split to calculate the project’s economy. The economic indicators that will be evaluated are the Net Present Value (NPV) and sensitivity analysis is also conducted to observe the change of NPV. The parameters for sensitivity analysis are Capital Expenditure (CAPEX), Operating Expenditure (OPEX), Oil Production, and Oil Price. It is found that LSWI implementation using Gross Split is more profitable than PSC. The parameters that affects NPV the most in all PSC cases are the oil production and oil price. On the other hand, in Gross Split cases, the oil production is the parameter that affects NPV the most, followed by oil price. The novelty of this study is in the comparison of project’s economy between WF and LSWI using two different fiscal regimes to see whether Gross Split is more profitable than PSC on EOR implementation, specifically the LSWI at Field X.

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

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

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

TUBING STRENGTH ANALYSIS AND FAILURE ASSESSMENT OF ELECTRICAL SUBMERSIBLE PUMP (ESP) WELL: A CASE STUDY ON PRODUCTION WELL “X” Brian Tony; Steven Chandra
Jurnal Mineral, Energi dan Lingkungan Vol 6, No 2 (2022): Desember
Publisher : Fakultas Teknologi Mineral, Universitas Pembangunan Nasional (UPN)

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jmel.v6i2.7701

This study will discuss the evaluation of tubing strength in Well X that using Electrical Submersible Pump as an artificial lifting method. The evaluation will be carried out to determine the risk of failure of production tubing due to erosional damage and the failure due to loads on tubing during production operation using Electrical Submersible Pump. Burst, collapse, and tension loads will be the main focus in evaluating the tubing load by considering the worst conditions that may be experienced during production operation. The calculation of the tubing load is done using Microsoft Excel. The result of tubing load calculation will be compared with the tubing rating based on tubing grade. Erosional damage prediction is carried out using software to determine the erosional velocity on the production tubing.This study will evaluate the production tubing used in Well X with an outer diameter of 3.5 inch and L-80 tubing grade. Tubing L-80 has a burst rating of 7240 psi, a collapse rating of 10533.92 psi, and a tension rating of 107581.11 lbf. Tubing is rating will be the limit that determines the integrity of the well during the production period. Based on the evaluation result, L-80 production tubing that using Electrical Submersible Pump as an artificial lifting method is able to withstand the burst load, collapse load, tension load, and the erosional effect of the produced fluid. Therefore, the Electrical Submersible Pump in Well X as an artificial lift system can be carried out without changing the grade of the existing tubing production.

TUBING STRENGTH ANALYSIS AND FAILURE ASSESSMENT OF ELECTRICAL SUBMERSIBLE PUMP (ESP) WELL: A CASE STUDY ON PRODUCTION WELL “X” Brian Tony; Steven Chandra
Jurnal Mineral, Energi dan Lingkungan Vol 6, No 2 (2022): Desember
Publisher : Fakultas Teknologi Mineral, Universitas Pembangunan Nasional (UPN)

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jmel.v6i2.7701

This study will discuss the evaluation of tubing strength in Well X that using Electrical Submersible Pump as an artificial lifting method. The evaluation will be carried out to determine the risk of failure of production tubing due to erosional damage and the failure due to loads on tubing during production operation using Electrical Submersible Pump. Burst, collapse, and tension loads will be the main focus in evaluating the tubing load by considering the worst conditions that may be experienced during production operation. The calculation of the tubing load is done using Microsoft Excel. The result of tubing load calculation will be compared with the tubing rating based on tubing grade. Erosional damage prediction is carried out using software to determine the erosional velocity on the production tubing.This study will evaluate the production tubing used in Well X with an outer diameter of 3.5 inch and L-80 tubing grade. Tubing L-80 has a burst rating of 7240 psi, a collapse rating of 10533.92 psi, and a tension rating of 107581.11 lbf. Tubing is rating will be the limit that determines the integrity of the well during the production period. Based on the evaluation result, L-80 production tubing that using Electrical Submersible Pump as an artificial lifting method is able to withstand the burst load, collapse load, tension load, and the erosional effect of the produced fluid. Therefore, the Electrical Submersible Pump in Well X as an artificial lift system can be carried out without changing the grade of the existing tubing production.

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

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.

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