Indonesia Conference Directory

Corresponding Author
Rizky Arif Putra

Institutions
a) Petroleum Engineering Department, Bandung Institute of Technology
Jalan Ganesha 10, Bandung 40132, Indonesia
b) Petroleum Engineering Department, Bandung Institute of Technology
Jalan Ganesha 10, Bandung 40132, Indonesia
c) Petroleum Engineering Department, Bandung Institute of Technology
Jalan Ganesha 10, Bandung 40132, Indonesia
d) Petroleum Engineering Department, Bandung Institute of Technology
Jalan Ganesha 10, Bandung 40132, Indonesia
e) Petroleum Engineering Department, Bandung Institute of Technology
Jalan Ganesha 10, Bandung 40132, Indonesia

Abstract
Gas lift has been successfully operated in many types of oil wells around the world. Many techniques have been derived to increase gas lift efficiency, not only from gas lift modeling but also technical designs of gas lift components have been tweaked to produce higher gas lift performance with less gas injected. Gas Lift Performance Curve currently holds as one of the most prominent evaluation method of gas lift performance. The method itself is derived as a subcomponent of Inflow Performance Relationship (IPR) curves that allows simple and robust GLP curve generation without having to perform procedural, iterative calculations. It is worth noting, however, that GLP curves cannot be held as a single culmination parameter in determining the efficiency of gas lift systems. This study introduces a new paradigm in modeling the performance of gas lifted wells by utilization of mechanistic fluid flow modeling. Mechanistic models, unlike conventional GLP curves, are generated from observations in full scale laboratory experiments, therefore complications in multiphase flow pattern, such as flow pattern transition can be fully acknowledged and incorporated into the calculations. Based on the previously stated hypothesis, this study offers a case study on marginal oil well where gas lift acts as the main extraction method. Observations done in the model has confirmed the functionality of Flow Pattern Map (FPM) derived from mechanistic modeling as a complementary check and balance tool for gas lift systems. It is also expected that the FPM will perform well in a multitude of gas lift case studies due to its versatility.

Keywords
Gas lift; Flow regime; Mechanistic model; Two phase flow; Optimum gas lift rate

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/6dGykaYUK8fm

Corresponding Author
Boni Swadesi

Institutions
(a) UPN Veteran Yogyakarta
(b) Institut Teknologi Bandung

Abstract
Polymer flooding is one of the methods to improve sweep efficiency and reduce water mobility when water channeling takes place in an oil reservoir. Theoretically, if the polymer viscosity increases, the mobility ratio decreases. Thus, the oil sweep becomes more efficient while the recovery factor (RF) becomes higher. However, there is a phenomenon in which polymer with higher viscosity does not always improve oil recovery. One of the factors that influence this phenomenon is the existence of Inaccessible Pore Volume (IPV), so this study is needed to determine the relationship between polymer rheology and the amount of IPV. Two commercial polymers with the same concentration, FP3630S and ChemEOR, were done by rheology testing and injected into a number of sandstone Berea cores. The effluents of salt tracer (potassium iodide) and polymer flood were collected, and their concentrations were measured using atomic absorption spectroscopy (AAS) and UV-Vis spectrometry, respectively. Based on Rheology test in the same concentration, polymer ChemEOR has a higher viscosity, but from the Coreflood test, ChemEOR has smaller oil recovery than FP3630S. The IPV of ChemEOR and FP3630S were 30.6 % and 23.12%, respectively. The size of IPV of a polymer is influenced by the ability of the polymer to increase viscosity, so that the greater the value of the viscosity given, the greater the value of IPV from the polymer. The FP3630S polymer can reach larger rock pores even though in terms of the water-oil mobility ratio is smaller than ChemEOR. With a smaller IPV, the result proves that FP3630 polymer displays an increase of oil recovery compared to ChemEOR polymer.

Keywords
Inaccessible Pore Volume, Polymer Flooding, Coreflood

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/gVn7aJW3bYZF

Corresponding Author
Dwi Atty Mardiana

Institutions
a) Faculty of Technology, Earth and Energy, Universitas Trisakti.
Jl. Kyai Tapa No.1 Jakarta
dwi_atty[at]yahoo.com
b) Faculty of Technology, Earth and Energy, Universitas Trisakti.
Jl. Kyai Tapa No.1 Jakarta
burhan[at]trisakti.ac.id

Abstract
The new fiscal scheme in the upstream petroleum industry has been implemented in Indonesia since 2017. Combination split at each parameter might not reflective to the various economic conditions. The difference between well-developed and new frontier offshore categories is only two percent. Yet, field size for the offshore new frontier areas should have significant larger reserves to justify the new pipelines and other infrastructure compare with the next offshore field that might would utilized the well-developed offshore facilities. This study will analyze the fiscal model calibration for the variable component of infrastructure in one offshore field, through its economic indicator. Sensitivity of the infrastructure development would be applied, that would affect to the capital investment, the operating cost, and production scenario. The study found that the composition of the split is not reflective to the various development and economic conditions. It is suggests that the new gross split scheme should be designed to apply to different levels of infrastructure in the same certain working area.

Keywords
petroleum economic, gross split scheme, variable component

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/e4haqDMvbkgR

Corresponding Author
Harry Budiharjo S

Institutions
1)Program Studi Teknik Perminyakan, FTM, UPN “Veteran” Yogyakarta
2)Program Studi Teknik Kimia, AKPRIN Yogyakarta

Abstract
Kawengan Field has reached the peak of its production and currently is being developed an Enhanced Oil Recovery (EOR). In this research bio-surfactants will be used as substance that will be injected into reservoir. Bio-surfactants are as surfactant from microorganisms and can work to reduce interfacial tension (IFT) so that it can be applied in EOR. The other advantages of bio-surfactant are being able to reduce oil viscosity in reservoir temperatures, higher biodegradation rates and low toxicity. This research used Kawengan Field oil samples before and after being given bio-surfactants. In laboratory test, the viscosity and IFT will be measured. Viscosity shows the phase changes and IFT shows bio-surfactants can reduce IFT between water-oil. The aim of this research is to provide an overview of the application of bio-surfactants as a good and viable alternative to expensive chemical surfactants in increasing oil recovery.

Keywords
Bio-surfactant, EOR, IFT

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/Q2N8x7gymZf9

Corresponding Author
Diah Rini Ratnaningsih

Institutions
* Pertamina
** UPN Veteran Yogyakarta

Abstract
The Ogan Komering Working Area has an area of 1,155 km2 located in the Ogan Komering Ulu District of South Sumatra Province. The Ogan Komering Working Area is currently operated by Pertamina Hulu Energi (PHE) Ogan Komering with a Gross Split Contract Agreement as of May 20, 2018. Waterflood project has implemented since 2006 in NEASD and GRH field. Ogan Komering Block has reached second peak production with 5,980 BOPD on early 2011. Because of plugging, the injection rate nowadays is only 16,000 BWPD when once it reached 40,000 BWPD. Remaining reserves in NEASD and GRH field is 4.04 MMBO based on updating GGR study in 2019. With enhancement injection rate, NEASD and GRH field are expected to increase 2-3 MMBO reserves. The further study about waterflood subsurface condition is conducted related to connectivity between injection well and production well also the injection performance in NEASD and GRH field to complete the target. From connectivity analysis supported with geophysic and geology interpretration, waterflooding in NEASD and GRH field consists of 4 areas which are A, B, C, and D. This analysis will be one of the guideline study for mature waterflood optimization. The connectivity between injection and production wells are important thing to optimize mature waterflood project. This paper report the tracer running result on 2006 and injection-production wells performance plot to evaluate reservoir connectivity. Tracer analysis was conducted to analyze the connectivity between injection and production wells. The tracer is injected to the several injection wells and will be expected to flow to the monitor wells considered as production wells. Several type of tracers were injected into 11 injection wells on June, 23rd until 27th 2006 and September, 10th 2006. The 11 injection wells are ASDJ-27, GRH-4, ASDJ-34, GRH-10, GRH-16, GRH-7, ASDJ-41, ASDJ-36, GRH-6, ASDJ-31, dan ASDJ-33 which is located in different section area which the injection wells has pattern peripheral. The tracer were expected to flow to the monitor wells (production wells) nearly located to the corresponding injector well. In Area A, tracer 158a in the amount of 100 liters was injected to ASDJ-34 and it was detected to ASDJ-22 after 453 days. However, performance plot shows that injection rate did not affect the liquid production rate. From geology interpretation, it is confirmed that there is minor fault in 1 km which is considered as minor leaking. Tracer 140c was injected to ASDJ-31 in Area B. In the span of time 553 days, tracer 140c was detected in ASDJ-74. The performance plot also confirmed that liquid production rate and oil production rate have a tendency of increment when injection well was started on June 2007. Several types of tracer were injected to Area-C but there were no tracer detection in monitoring wells. In Area D, Tracer 140c which was injected to GRH-6 was detected in GRH-22 after 70 days and Tracer 140a from GRH-10 was detected in GRH-13 after 927

Keywords
Connectivity Analysis, Tracer Wells

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/daP2kjh7E3ZH

Corresponding Author
joko mulyono

Institutions
- UPN (Magister Teknik Perminyakan)

Abstract
Connectivity Analysis Using of Tracer or Injection-Production Wells Performance Plot In NEASD And GRH Field PHE Ogan Komering Authors : Joko Mulyono, S.T., Firman Edi, S.T., and Dr. Ir. Dyah Rini Ratnaningsih, M.T. 2)Petroleum Engineering Magister Universitas Pembangunan Nasional “Veteran” Yogyakarta, Indonesia Corresponding author: a) joko.mulyono@pertamina.com; b)firman.edi@pertamina.com c)rini_diah@yahoo.com Abstract. The Ogan Komering Working Area has an area of 1,155 km2 located in the Ogan Komering Ulu District of South Sumatra Province. The Ogan Komering Working Area is currently operated by Pertamina Hulu Energi (PHE) Ogan Komering with a Gross Split Contract Agreement as of May 20, 2018. Waterflood project has implemented since 2006 in NEASD and GRH field. Ogan Komering Block has reached second peak production with 5,980 BOPD on early 2011. Because of plugging, the injection rate nowadays is only 16,000 BWPD when once it reached 40,000 BWPD. Remaining reserves in NEASD and GRH field is 4.04 MMBO based on updating GGR study in 2019. With enhancement injection rate, NEASD and GRH field are expected to increase 2-3 MMBO reserves. The further study about waterflood subsurface condition is conducted related to connectivity between injection well and production well also the injection performance in NEASD and GRH field to complete the target. From connectivity analysis supported with geophysic and geology interpretration, waterflooding in NEASD and GRH field consists of 4 areas which are A, B, C, and D. This analysis will be one of the guideline study for mature waterflood optimization. The connectivity between injection and production wells are important thing to optimize mature waterflood project. This paper report the tracer running result on 2006 and injection-production wells performance plot to evaluate reservoir connectivity. Tracer analysis was conducted to analyze the connectivity between injection and production wells. The tracer is injected to the several injection wells and will be expected to flow to the monitor wells considered as production wells. Several type of tracers were injected into 11 injection wells on June, 23rd until 27th 2006 and September, 10th 2006. The 11 injection wells are ASDJ-27, GRH-4, ASDJ-34, GRH-10, GRH-16, GRH-7, ASDJ-41, ASDJ-36, GRH-6, ASDJ-31, dan ASDJ-33 which is located in different section area which the injection wells has pattern peripheral. The tracer were expected to flow to the monitor wells (production wells) nearly located to the corresponding injector well. In Area A, tracer 158a in the amount of 100 liters was injected to ASDJ-34 and it was detected to ASDJ-22 after 453 days. However, performance plot shows that injection rate did not affect the liquid production rate. From geology interpretation, it is confirmed that there is minor fault in 1 km which is considered as minor leaking. Tracer 140c was injected to ASDJ-31 in Area B. In the span of time 553 days, tracer 140c

Keywords
Tracer, Waterflood, Connectivity,

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/Jyc76BFRvj9w

Corresponding Author
Steven Chandra

Institutions
Petroleum Engineering, Institut Teknologi Bandung

Abstract
Field X is an offshore field that is included in the deep-water area managed by an oil and gas company in Indonesia. From a number of tests conducted it was found that are presence of sand problems in this field especially in well G1 so that several studies were conducted. From the results of the study, it is determined that the use of Frac pack is one of the most appropriate ways, besides controlling sand problems, it also increases gas production on field X. The Frac pack method is a well stimulation by combining gravel pack to control the sand problems with hydraulic fracturing which is designed to have high conductivity to increase productivity over the well. In this paper, a calculation model is developed to find out the optimum fracture half length, fracture width and also the pumping schedule of the Frac pack with sensitivity of proppant concentration. Then the results will be compared with existing commercial software. The challenge faced in frac pack modeling for well G1 is large permeability so that the possibility of leakage occurring is greater and then handled by increasing the injection rate. Based on the calculations and analyzes that have been done, for the well G1 on field X it will be optimum to operate if frac pack is installed with the type of brady sand 20/40 proppant and dynafrac HT 30 as fracturing fluid, so that half fracture length, X_f 76.8 ft is obtained with fracture width, w_f 0.4355 ft and 5 times fold of increase in the production. From this study it can be concluded that the calculation model made can be accepted and used commercially.

Keywords
Frac pack, fracture half length, fracture width, fold of increase

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/vD4FupBJyHRg

Corresponding Author
Muhammad Taufiq Fathaddin

Institutions
(a)Univeritas Trisakti, Faculty of Earth Technology and Energy, Indonesia
(b) Pertamina Hulu Energi Tuban East Java, Jakarta, Indonesia
(c) Universitas Jember, Faculty of Engineering, Indonesia
(*)muh.taufiq[at]trisakti.ac.id

Abstract
High viscosity which is an inherent property of heavy oil would give an inconclusive result on a Pressure Draw-down Test. Some kind of thermal injection should be performed prior to implementing the operation of Pressure Draw-down Test, where the heat will reduce the viscosity of the reservoir fluid. The study was aimed to design a proper Pressure Draw-down Test for N-7 Well using a simulator. Since the well test was intended to reach radial flow regime then the viscosity should be reduced from 1069 cp to 66.5 cp for production time of 500 hours or to 24.8 cp for production time of 100 hours. Sensitivity test of several parameters namely viscosity, permeability, porosity, and shut-in time was conducted to analysis the effect of the parameters on the radius of investigation and radial flow time. This sensitivity would give various radius of investigation. Furthermore, the study was continued to correlate radius of investigation as a function of the parameters mentioned above. Permeability and shut-in time are directly proportional to radius of investigation. While porosity and viscosity are inversely proportional to the radius of investigation.

Keywords
Pressure Draw Down Test, Pressure Derivative, Heavy Oil, Radius of Investigation

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/2kKqJaUFfyhb

Corresponding Author
allen haryanto

Institutions
UPN Veteran Yogyakarta

Abstract
Geothermal energy utilizes steam from earth subsurface to drive turbines, which then produce electrical energy. The remaining brine from the process will return to the reservoir through injection wells. The brine basically can be utilized before injection, since it has high temperature, for other direct use. This paper aims to analyze the brine as a heat exchanger fluid, and calculate the energy requirements for meeting room heaters, and then determine the design of Heat Exchanger (HE). The meeting room has a 20-cm thick wooden wall, with dimensions of 20103 m3. The room temperature will be set to be 21-27 C. The geothermal source is at 300 m from meeting room and its elevation is 20 m below. The brine temperature that will be utilized is 100 C, and it has 20 gpm and outdoor temperature is 14 C. The result of the design is the fluid flow from the heat source to the output that warms the room. The flow is divided into 4 stages: at the pump, heat exchanger, air transmission and the room. The estimated cost of the heat exchanger is then calculated based on the design.

Keywords
Geothermal energy, Heat Exchanger, estimated cost,

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/kaPvqgRyDTN8

Corresponding Author
RINI SETIATI

Institutions
Universitas Trisakti
Institut Teknologi Bandung

Abstract
This study was aims to demonstrate that bagasse as a waste can be used for enhanced oil recovery process. Bagasse has sufficient lignin content to be processed into sodium lignosulfonate surfactant. The use of bagasse as raw material of surfactant for the chemical flooding is the development in the science of petroleum. Synthesized bagasse to lignosulfonate was done by isolation process using sodium hydroxide reagent and sulfonation process using sodium bisulfite reagent. From FTIR test and NMR test, sodium lignosulfonate (SLS) surfactant from bagasse consist of sulfonate groups (hydrphilic groups) and benzene (lipophilic groups). The synthesized SLS surfactant of bagasse has a HLB value of 11.62. The presence of hydrophilic and lipophilic components resulted in the stability of middle phase emulsion in the range of 5% - 10% and the core flood obtained recovery factor reaches 1.05% - 9.50%. With HLB value of SLS surfactant from bagasse indicated that it can be used as an injection fluid in the oil/water emulsion system, which is indicated by the presence of a middle-phase emulsion. Conclusion of this study indicate that the synthesized lignosulfonate of bagasse can use an injectin fluid in O/W emulsion and bind oil and water to form microemulsions. The bagasse is a local raw material for sodium lignosulfonate (SLS) surfactants which can be useful for enhanced oil recovery.

Keywords
bagasse, middle phase emulsion, sodium lignosulfonate(SLS), surfactant flooding,, recovery factor

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/RT4gKJCVYvpd

Corresponding Author
Nugroho Marsiyanto

Institutions
PHE, Jl T.B. Simatupang Kav 99, PHE Tower, Jakarta Selatan 12520 [1]
Petroleum Engineering Department, Engineering Faculty, Bhayangkara Jaya University
Kampus II, Jl. Raya Perjuangan Kel. Marga Mulya, Bekasi Utara, Kota bekasi Jawa 17121[2]

Abstract
ASD Block PSC Area is located in South Sumatera, about 40 km south of Prabumulih, South Sumatera. The ASD-1 well is first exploration well and discovered oil at the end of 1988. Until May 2011, there were 24 exploration wells and 147 development wells drilled and produced. ASD block has been producing since November 1989. In 2011, the oil production was about 5800 BOPD, and 15 MMSCFD of producing gas and mostly the lifting equipment was dominated by Electric Submersible Pump (ESP) and the rest was Sucker Rod Pump (SRP). Total ESP was 67 oil producer wells meanwhile SRP was 4 oil producer wells. Since there were a lot of number and need of consumable parts of ESP units, the study is focusing on the impact of ESP power cable which is giving the significant impact on oil production if the wells down due to ESP power cable failure, such as shortage and also cost in purchasing the ESP power cable. This paper evaluated the well failures caused by the bad quality of ESP power cable. There were 3 ESP power cable brands used in 2011, namely X, Y Z where each of the brands had different quality. Through physical band test to the power cable and well failures caused by it, it would come up with the recommendation which ESP power cables had to be used in AS block. The ESP well failures data are taken from the year 2011-2015. Based on data shows improvement on reducing ESP well failures after followed the recommendation not to install X ESP power cable brand. From this study, it can avoid potentially lost about USD 1,786,562 due to well failures caused by X power cable and save actual cost about US$ 538,292 from procurement process to provide ESP power cable need for the year 2011-2015.

Keywords
lifting, electric submersible pump, sucker rod pump, power cable, well failure

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/T3kdYnrVUHJq

Corresponding Author
Widhilaga Gia Perdana

Institutions
a) Environmental science, University of Indonesia, Jl. Margonda Raya, Pondok Cina, Beji, Kota Depok, Jawa Barat 16424
*widhilaga.gia[at]ui.ac.id
b) Faculty of Engineering, University of Indonesia, Jl. Margonda Raya, Pondok Cina, Beji, Kota Depok, Jawa Barat 16424
c) Faculty of earth and energy technology, Trisakti university, Univ. Trisakti Kampus A, Gedung D Lantai 5, Jalan Kyai Tapa, Grogol, RT.6/RW.16, Tomang, Grogol petamburan, Kota Jakarta Barat, Daerah Khusus Ibukota Jakarta 11440

Abstract
The population growth rate and economic growth that increase every year results in increased energy needs that are used to support human activities in daily life. Energy consumption in Indonesia comes from petroleum, coal, natural gas, renewable energy (EBT), and hydropower. Petroleum has the largest portion of energy consumption in Indonesia where upstream oil and gas activities, namely exploration and exploitation carried out to meet energy needs, have not been able to meet domestic energy needs. On the other hand, the decline in the economic level of the upstream oil and gas industry due to changes in world crude oil prices has resulted in reduced investment in this industry. By looking at the condition of non-renewable petroleum natural resources, the tendency for oil and gas needs to continue to increase, while the availability and oil and gas reserves are always decreasing, this has an impact on the upstream oil and gas industry in Indonesia. Looking at it from the standpoint of Sustainability Theory, where meeting current needs without sacrificing the needs of future generations can be applied to the upstream oil and gas industry. Using the Artificial Neural Network method to create a model that can see the behavior of the carrying capacity of oil and gas exploration and exploitation activities in Indonesia which consists of petroleum reserves, the rate of petroleum production, and investments that can be used as a policy-making instrument to support sustainable development goals in the upstream oil and gas industry in Indonesia.

Keywords
Oil and gas, Upstream industry, Carrying capacity, Artificial neural network

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/YTRf79pvXNjB

Corresponding Author
Arizona Yoris Wirawan

Institutions
1,3,4,5) Petroleum Engineering Study Program, Faculty of Mineral Technology, UPN “Veteran” Yogyakarta Jln SWK Ring Road Utara Condong Catur 55283;
PT PLN (Persero), Jl. Truno Joyo Blok M1 no 135 Jakarta Selatan
*yorisarizona17[at]gmail.com

2) Petroleum Engineering Study Program, Faculty of Mineral Technology, UPN “Veteran” Yogyakarta Jln SWK Ring Road Utara Condong Catur 55283

Abstract
Geothermal is a potential renewable energy source to be developed in Indonesia. Indonesias geothermal energy potential is recorded at 28,579 MW, but has only been utilized for electricity generation of around 1,948.5 MW. Investment in geothermal power plants is an investment that is capital intensive with high investment risk factors. This study aims to determine the financial feasibility of investing in geothermal power plants in the Gedongsongo geothermal field with 55 MWe of potential electrical energy. In addition, research is conducted to find out from the beginning of the project implementation to the end of the projects economic life and to determine the feasibility level of financial feasibility of investment in the project. The results of investment analysis use sensitivity analysis, indicating that price movements in project calculations have a large influence on changes in NPV. Sensitivity analysis is carried out on several parameters that affect the project value (in the form of NPV) with a Low Case of 70% parameter value and High Case of 130%. The inflation rate for operating costs such as O & M, Make Up Well Drilling and Overhaul is assumed to be 2% per year. Project financing is assumed to originate from personal capital of 30% and loans of 70% with interest rates (interest) of 4% per year. To get the value of the internal rate of return on personal capital or the Equity Internal Rate of Return in accordance with PLN standards of 14%, the electricity tariff for the Gedongsongo Geothermal power plant is USD 11.45 cent / kWh.

Keywords
Keywords : Geothermal power plant, feasibility, sensitivity analysis, electricity tariff

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/HQvmegTLNuCy

Corresponding Author
Panca Suci Widiantoro

Institutions
(a)Program Studi Teknik Perminyakan , Akademi MIGAS Balongan, Indramayu.
(b)Program Studi Teknik Perminyakan, Fakultas Teknologi Mineral, UPN “Veteran” Yogyakarta.

Abstract
Gas Well PCA was produced in February 1994. This well is produced commingle of 2 reservoirs A and B. DST result shows both two reservoirs have contrast deliverability. The last production test shows gas rate 7.28 MMSCFD. This well purposed to further workover program to obtained optimum recovery. Integrated production modelling is essential for well performance analysis, enhancement of the production system. Gas well performance cannot be analyzed without considering the reservoir, the flowline and the processing facility, as each of these components affect the operation of the entire production network. This study will take into account the effect of comingle of 2 layers with contrast deliverability by building integrated production model. The Inflow Performance Relationship (IPR) Curve will be analyzed each reservoir to know each production performance. History matching analyses also performed to check the reliability of model in dynamic condition. To achieve the accurate history matching results, the simulation model was run based on the available historical production data. Based on this study, current recovery of A reservoir was 55%, B reservoir was 75% and reservoir B already water out. It is recommended to do workover on this well by isolate reservoir B then re-perforate reservoir A and produce gas only from reservoir A to get optimum recovery.

Keywords
Commingle Gas Well, Integrated production modeling, Workover

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/pafzkJGuh8yW

Corresponding Author
Bayu Satiyawira

Institutions
Universitas Trisakti

Abstract
Drilling mud is the most important part in drilling activity. Drilling could work fluently, save, and economical on fluence by system and condition of drilling mud. It means the mud system and the physical properties of the slurry conform to the required specifications. There are some kind of drilling mud that can be use on oil and gas drilling operation, such as water base mud and oil base mud. In terms of economical, water base mud is usually use in drilling process. The purpose of this study is to find conducted laboratory research of the effect of differences temperature for characteristic mud system of low solid mud with adding biopolimer and bentonite extender. This research used roller oven method as a medium for simulation to condition the mud as if to be in the well to see the change of physical properties of sludge at differences temperature. The result is found that the higher the temperature, the drilling mud physical properties like density, viscosity, plastic viscosity, yield point, dial reading 600 RPM, dial reading 300 RPM, and gel strenght decrease. But not all the physical properties decreased.

Keywords
LABORATORY STUDY OF THE EFFECT OF VARIOUS TEMPERATURES ON THE PHYSICAL PROPERTIES OF LOW SOLID MUD SYSTEMS

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/EgvrAMW63FY4

Corresponding Author
Andry Prima

Institutions
Universitas Trisakti
Faculty of Earth Technology and Energy
Petroleum Department,

Abstract
Drilling mud is the most important part in drilling activity. Drilling could work fluently, safely, and economically on fluency by system and condition of drilling mud. It means the mud system and the physical properties of the slurry conform to the required specifications. There are some kinds of drilling mud that can be used in oil and gas drilling operation, such as water base mud and oil base mud. In terms of economical objective, water base mud is usually used in drilling process. The purpose of this study is to conduct laboratory research of the effect of various temperatures on the characteristic of mud system of low solid mud by adding biopolymer and bentonite extender. This research uses roller oven method as a medium for simulation to condition the mud as close as possible to the condition in wellbore to see the change of physical properties of sludge at various temperatures. The result found is that the higher the temperature, the lower the drilling mud physical properties such as density, viscosity, plastic viscosity, yield point, dial reading 600 RPM, dial reading 300 RPM, and gel strength. However, it is found that not all the physical properties decrease.

Keywords
drillig mud, bentonite, extender, mud cake, polymer, pH, laboratory study

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/gamcL439YGFA

Corresponding Author
MiaFerian Helmy

Institutions
1). Dosen Prodi Teknik Perminyakan
2). Mahasiswa Prodi Teknik Perminyakan

Abstract
AST-04 well is a production well located in Riau, this well currently has two production Layers (SD_04 has oil reserve and SD_05 has gas reserve). Using commingle completion the oil production in this well is below expectation. This problem caused by SD_05 gas production with high pressure which through SD_04 perforation hamper the oil flow. Re-completion design using multiple completion become a solution to improve oil production. Oil from SD_04 will be flowed using short string, while gas from SD_05 using long string. By Vogel Equation, the redesign results production increase to 290 BOPD with natural flow using tubing size 2 7/8 inch. To utilize SD_05 gas production and increase SD_04 oil production, natural gas lift selected to assist oil lifting. Gas produce from SD_05 will be injected to short string (SD_04 perforation area) through orifice. This method expected can increase oil production SD_04 layer to 406 BOPD with injection rate 1,367 MMSCFD. Using Craft, Holdden, & Graves equation, the orifice size 16/64 needed to flow the gas with injection rate desired.

Keywords
Multiple Completion, Natural Gas Lift, Production Optimization

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/zA7PB6aKFWcg

Corresponding Author
Listiana Satiawati

Institutions
Program Studi Tenik Perminyakan, Fakultas Teknologi Kebumian dan Energi, Universitas Trisakti.
Jl. Kyai Tapa no. 1 Grogol Jakarta Barat 11440

Abstract
Proper and careful planning on the calculation of discharge in pipes in a system of three or more reservoirs are very important for the oil or the drinking water industry, as a collecting channel or as a fluid distribution. The discharge of fluid entering the pipe and coming out of the pipe can be calculated assuming the discharge flow is close to zero at the branching of the piping system. The debit calculation in this system can be done analytically and numerically, the numerical calculation will be faster than the analytical method. There are a number of analytical and numerical calculations that have been carried out by previous researchers, in this paper we do calculations by coding using other languages, namely Fortran. Calculations use data including elevation, length, diameter, roughness and friction factor from the pipe as well as Reynolds number data. Also uses the Moody Diagram, and the equations used are Bernoulli Equations, Continuity Equations, and Darcy-Weishbach Equations. In this paper numerical calculations using the Fortran program have been performed by displaying flow chart, coding, and the results of numerical calculations. The results obtained are quite in accordance with the results that have been calculated first, namely using the analytical method and linear interpolation by Streeter and numerical calculations that use Hardy Cross Method by Potter and Douglas. Deviation between our calculations with previous calculations, both analytically and numerically around 1%. So we conclude that our coding can be used for the calculation of debit in the three reservoir system planning. We present the numerical calculation results in the form of partial data while the complete data is presented in graphical form. This research can be continued to calculate a system of more than three reservoirs.

Keywords
Discharge, Reynolds Numbers, Moody Diagram, Bernoulli Equations, Continuity Equation, Darcy-Weishbach equation, Three Reservoir System

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/HcYQBqpbFtVR

Corresponding Author
Steven Chandra

Institutions
Petroleum Engineering Department
Institut Teknologi Bandung

Abstract
Despite the slow growth of EOR development in Indonesia, CO2 EOR has recently gained its momentum due to its versatility to diverse reservoir systems in Indonesia. Optimizing CO2 Injection in EOR activity is a must, since no incentive or tax holiday is given in Indonesia for this activity, contrary to the majority of policies around the globe. This study offers an innovative approach of CO2 flooding injection rate determination using closed loop optimization in project economic evaluation. Particle Swarm Optimization (PSO) algorithm was implemented as a method of optimizing the injection rate of CO2. These novel algorithms are known and proven to be able to work with massive number of datasets, as well as identifying and separating bad dataset(s). The result is optimum injection rate that brings maximum economical value to the project. Utilization of this method increases the NPV of the project by 10.4% and 12% increase in RF.

Keywords
CO2 EOR; Closed Loop; Particle Swarm Optimization

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/wNVn49rBfRhv

Corresponding Author
Feby Zulkarnain

Institutions
Study Program Magister Of Petroleum Engineering
Pembangunan Nasional University Of Veteran Yogyakarta

Abstract
PT. Pertamina Hulu Energi Ogan Komering (PHE OK) Water injection began in 1998, by injecting excess water in abandoned wells in Central ASD and continued in October 2000 and January 2002, and since May 2006 the injection rate was increased above 30,000 BWPD. From the analysis carried out, one of the obstacles in the injection water process at PHE OK is the main pipe capacity of the injection water which is getting smaller and the pressure drop along the pipe is very big. The pressure drop occurs due to the solid / deposition pile on the inside of the pipe, causing obstacles in the process of transferring injection water from the Block Station to the injection wells. From the laboratory analysis, the solid deposits inside the pipe wall is consist of more than 50% organic and hydrocarbon matters (paraffin, oils, and light asphaltene) often called as “Schmoo” deposit. Some pigging activities can not be done due to pipe size, pipe geometry that does not support, pipe construction that is not designed for pigging activities. To overcome the solid deposit problem, PHE OK carried out a field trial of Schmoo Remover Chemical to clean the pipe without using pipe pig. From the field trial result, the removal of the schmoo solid deposit resulted in a significant increase in water injection rates and decrease pipe pressure drop.

Keywords
Schmoo, cleaner, solid deposit, surfactant, water injection

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/RrLJ9CkVjdE2

Corresponding Author
Dewi Asmorowati

Institutions
Petroleum Engginering Departmen, Faculty of Mineral Technologi, UPN “Veteran” Yogyakarta

Abstract
The free water table is located at the base of a hydrocarbon column and the transition zone. The free water table indicate the fluid contacts which are critical for field reserve estimates and for field development. Estimation of free water table usually using capillary pressure versus water saturation graph from SCAL data, but in this case the free water level is estimated by logging data with Pickett-s plot method. This technique use petrophysical parameters on log-log graph of porosity versus resistivity to determine reservoir characterization, one of this is height above free water table. The advantages of this method are low cost accurate in simple lithologies and unreliable in complex lithologies or low resistivity sands. The Pickett-s plot method is determined by predicting petrophysical parameters (a, m, n) and formation water resistivity (Rw) first. Next, the determination of straight line water saturation (Sw), permeability (k), capillary pressure (Pc), and height above free water table (h). The study takes data from 2 wells (Y-1 and Y-2 ) on the Petro field Pematang formation. From the calculation, the height above free water table of Well Y-1 upper formation is about 88.5-1150.4 m and lower formation is about 159.3 – 973.5 m, Well Y-2 is about 265.5 – 1327.4 m.

Keywords
pickett-s plot, free water level, resistivity

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/E3rLeRUGBcWM

Corresponding Author
edgie yuda

Institutions
Universitas Pembangunan Nasional "Veteran" Yogyakarta

Abstract
The production method of MEZ-1, MEZ-2 and MEZ-3 wells produce is a natural flow. However, during the fluid production process from the reservoir to the surface on the oil field, the production rate is decline because of the decrease in reservoir pressure. The decrease in the production rate was due to the bottom hole pressure not being able to lift the production fluid to the surface. Another factor is due to the influence of the production fluid phases which is flowed to the surface, which will affect the rate of oil production obtained. Therefore, optimization is needed to increase the rate of production in these wells. Production optimization conducted by changing the production method using artificial lifts. In optimizing production, the thing that needs to be considered is screening criteria from the artificial lift that is in accordance with the condition of the wells. The first thing to do in optimizing production is collecting and validating field data, then identifying reservoir types and behavior. Therefore, determine the formation of productivity, namely productivity index and inflow performance relationship (IPR). Calculating the MEZ-1 and MEZ-3 wells IPR using the Pseudo Steady State Method and the MEZ-2 well using the Vogel Method. Furthermore, calculating the existing wells and determining the desired production rate, then screening the criteria for the lifting method. The replacement of production methods on the "MEZ" field is carried out by artificial lift methods, namely Electric Submersible Pump (ESP). The selection of artificial lift methods will be used by looking at the screening criteria of each artificial lift method that is in accordance with the well condition on the "MEZ" field and found that in the "MEZ" field well the production method replacement optimization is carried out using ESP. According to ESP artificial lift method criteria are ESP can be operated at a high rate, high GOR, good in deviated wells. ESP planning on the "MEZ" field considering the amount of free gas produced, other than that calculating the sensitivity of pump intake pressure to various prices of production rates and Turpin values to determine the price of the optimum production rate for each well.

Keywords
production optimization; artificial lift, electric submersible pump

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/aVzF4gEDUT8w

Corresponding Author
M.Th. Kristiati

Institutions
Department of Petroleum Engineering, Universitas Pembangunan Nasional “Veteran” Yogyakarta

Abstract
The RYU Geothermal Field has 6 production wells, is a liquid dominated reservoir, the most common problem is silica scaling and flow patterns that can cause vibrations in the piping system so that it can potentially damage equipment. The effort to overcome this problem is to determine the production rate at the right well pressure. Evaluation of wellhead pressure focuses on the wellhead by considering the potential of silica scale based on the value of the SSI and the pattern of annular flow or wispy annular flow in the wellhead pressure conditions to prevent the effects of water hammer and electric power (MWe) that can be generated. The SSI (Silica Saturation Index) value is obtained from the output curve of the total mass rate and enthalpy with salinity correction, plot the flow pattern map with the Hewitt-Roberts model, while the potential electric power from the steam coming out of the separator using a 1 MWe correlation requires 8.2 tons / hour average vapor mass and separator pressure of 10.4115 barg or 11.2115 bar abs. The results showed that the wellhead pressure was 520-580 psig SSI value between 0.6291 - 0.6999, so there was no tendency to form silica scaling in the wellhead because the wellhead SSI value was below 1. According to the results of the Hewitt-Roberts Graph plot, under conditions wellhead pressure 520-580 psig forms an annular flow pattern or wispy annular flow at the wellhead so it does not cause problems. At wellhead pressure 520-580 psig has a potential between 7.65 MWe to 12.25 MWe at the pressure of separator 10.4115 barg or 11.2115 bar abs.

Keywords
Well head, SSI, flow pattern, electric power

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/Tm7y6DMnWkvz

Corresponding Author
Joko Pamungkas

Institutions
Department of Petroleum Engineering, Faculty of Mineral Technology, UPN Veteran Yogyakarta, Jalan SWK 104 (Lingkar Utara), Condong Catur, 55283, Yogyakarta, Indonesia

Abstract
Layer A on the X field has been produced since September 2007 until December 2016. This layer consists of 9 wells with current status: 1 production well (natural flow), 5 shut-in wells, and 3 dry-hole wells. The original oil in place of this layer is 28.113 MMSTB. The production data shows that oil cumulative production of this layer is 1.066 MMSTB, which means that the current recovery factor is 3.79 %. This number is very small, and since there is a lot of hydrocarbon area that have not been produced, an integrated reservoir simulation study is done to determine the optimum scenario for this layer development. The study begins with data collecting and processing; model validation through initialization, history matching and PI matching; remaining reserve determination; and simulation of field development scenarios. There are 5 scenarios simulated and until January 2043; Base Case (production of 1 existing well) gives 2.53 MMSTB or 9 % RF; Scenario 1 (Base Case + 3 gas lift wells) gives 3.15 MMSTB or 11.21 % RF; Scenario 2 (Scenario 1 + 3 development wells) gives 6.49 MMSTB or 23.09 % RF; Scenario 3 (Scenario 1 + 6 development wells) gives 7.68 MMSTB or 27.32 % RF; and Scenario 4 (Scenario 1 + 9 development wells) gives 7.58 or 26.97 % RF. From the reservoir simulation result, the optimum development scenario for this layer is Scenario 3.

Keywords
reservoir simulation; field development; optimum scenario

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/tNAvK4w6xrRm

Corresponding Author
Diah Rini Ratnaningsih

Institutions
1) Pertamina
2) UPN Veteran Yogyakarta

Abstract
ABAB Field is one of the fields operated by the Pertamina-EP Adera Business Unit located in South Sumatra. Found in 1951 and developed with a total of 137 wells with 8 productive reservoirs. As long as it is produced until now, in general, the category is still primary recovery, which is producing with natural energy capabilities from the reservoir. Although there is a small percentage of random water or peripheral water flooding. This is only intended for water disposal and at the same time to help maintain reservoir pressure. Reservoir that has been carried out by water injection is a reservoir of "A". This is because the driving mechanism in zone A is the drive depletion so that the reservoir pressure decreases quite rapidly and the lens shape is reservoir. The thickness of the average reservoir rate "A" is 20 ft. The "A" zone is a sand reservoir from Talang Akar, has OOIP = 52,823 MMSTB. Cumulative production until 12/14/2012 = 15,955 MMSTB (RF = 30%). One of the wells that was used as an injection well with the aim of pressure maintenance is the ABB-082 well. The ABB-082 well was drilled in 1974 and produced from the reservoir "A". Because the swap results are not indicative of oil (oil) and from the results of the survey the pressure gradient is interpreted as a water gradient of 0.41 psi / ft, in 1975 the well was converted to injection wells. Structurally the position of ABB-082 is higher (up dip) compared to the surrounding wells with a conical reservoir. In 1990 the well was no longer an injection well with shut-in status. In 2004 the ABB-082 well blew out by removing gas after shutting down for approximately 14 years. The average gas production amounted to 0.15 MMSCFD for 1 year, from 2004 to 2005 and then producing oil in natural bursts with an average production rate of 200 BOPD for approximately 2 years, from 2005 to 2007. Until now This ABB-082 cumulative production is Np = 290,356 MSTB. Well base with OOIP = 280,666 MSTB, then RF = 35% is calculated. From the description of the data, the ABB-082 well is a phenomenon of injection huff & puff with water injection (water flooding).

Keywords
Huff & Puff, Water Injection

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/AHDyhfErvXak

Corresponding Author
Lia Yunita

Institutions
Proklamasi 45 University

Abstract
Drilling fluid (mud) is an important factor in drilling. Geothermal reservoirs are often found in local and regional faults which result in large permeability so that it often results in lost circulation during the drilling process. To prevent this, the hydrostatic pressure of the drilling fluid must be as small as possible compared to the formation pressure by adding additives. Addition of natural ingredients as additives has advantages compared to chemicals which are affordable, easily available and abundant and environmentally friendly. The research method uses laboratory studies with basic ingredients of water and bentonite and the addition of natural ingredients additives. The independent variable of banana midribs is 5 grams and 10 grams at temperatures of 80 0F, 150 0F and 300 0F. The dependent variables are density, viscosity, plastic viscosity, gel strength, yield point, mud cake and filtration loss. The results showed that the best natural additives to resolve lost circulation.

Keywords
Mud Rheology, Natural Additives, Lost Circulation.

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/RXAxQVdgC689

Corresponding Author
Nendra Mulia Razak

Institutions
a. PT Pertamina Hulu Energi Siak
b. UPN "Veteran" Yogyakarta

Abstract
The background of this paper started from a massive MS and MK drilling campaign challenge in order to achieve contingent resources (2 C) and accelerate oil recovery. Besides that, those 2 (two) company are different entities with 384 km distance and heavy road terrain. Because of those challenges, required optimum rig capacity calculation and its scenario (use single rig/ without any replacement in completion phase or use double rig/ doing rig replacement in completion phase). To ensure rig calculation capacity has been aligned with field conditions and cost-efficiency principle, calculations was described both in technical and cost aspect. In technical aspect, there will be explained horsepower calculation based on well configuration. In cost aspect, there will be explained total cost comparison between usage of a single rig (drilling rig only) and a double rig (drilling & completion rig). Based on technical and cost calculation, concluded that the optimum rig capacity for doing drilling campaign is 427 HP with single rig usage (without rig replacement). Those things supported by ± 3.9 billion rupiahs cost-efficiency or 16% lower than double rig usage (using rig replacement for completion phase), and significant operation advantages by reducing duplicated work. Keywords: Massive Drilling Campaign, Rig Capacity Calculation, Cost-Efficiency, and Optimum Rig Capacity

Keywords
Massive Drilling Campaign, Rig Capacity Calculation, Cost Efficiency and Optimum Rig Capacity

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/hAXmYgq47u2E

Corresponding Author
Diah Rini Ratnaningsih

Institutions
Petroleum Engineering Magister Universitas Pembangunan Nasional “Veteran” Yogyakarta

Abstract
The problem of sand production is often found in oil fields from the layers of sandstone (rock sand) that are productive in shallow depths to deep ones. Sand production begins to occur if stress exceeds the strength of rock formations, the strength of these rock formations which is the strength of natural cementation of rocks in relation to granules of sandstone in formation. In addition, sand production is very sensitive to the rate of production, where at the critical production level, sand will be produced. In sandstone formations, cement granules cementing material is not consolidated, so that the sand will be produced starting from the beginning of the oil well being completed. Sandstone formations may not produce sand at the beginning of production, but after a certain production period sand begins. It can be understood that with decreasing reservoir pressure, each sand grain will increase the over burden pressure which then results in increased stress between the grains to exceed the ability of cementing material in the sandstone formation. Sand problems in oil production wells can greatly lead to shut down of production and the increased frequency of using Rig Services in intervention well activities, which caused increasing operational costs. One way to solve the problem is by using a Progressive Cavity Pump (PCP) where the movement of the rotor to the stator passes through the production fluid including sand that is produced to the surface so that the pump stuck problem due to the accumulation of sand can be overcome. In addition to the ability to overcome the sand, PCP provides a high level of pump efficiency reaching up to 75%.

Keywords
Unconsolidated sand, Rate Critical, Progressive Cavity Pump, Pump Efficient, pump stuck, Stress Formation, well intervention, Overburden Formation.

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/6PqBRCDvZ3cn

Corresponding Author
Zulkarnaen Yusuf

Institutions
1 ) PT Pertamina Hulu Energi Siak, Indonesia
2) Petroleum Engineering Magister UPN “Veteran” Yogyakarta, Indonesia

Abstract
The problem of sand production is often found in oil fields from the layers of sandstone (rock sand) that are productive in shallow depths to deep ones. Sand production begins to occur if stress exceeds the strength of rock formations, the strength of these rock formations which is the strength of natural cementation of rocks in relation to granules of sandstone in formation. In addition, sand production is very sensitive to the rate of production, where at the critical production level, sand will be produced. In sandstone formations, cement granules cementing material is not consolidated, so that the sand will be produced starting from the beginning of the oil well being completed. Sandstone formations may not produce sand at the beginning of production, but after a certain production period sand begins. It can be understood that with decreasing reservoir pressure, each sand grain will increase the over burden pressure which then results in increased stress between the grains to exceed the ability of cementing material in the sandstone formation. Sand problems in oil production wells can greatly lead to shut down of production and the increased frequency of using Rig Services in intervention well activities, which caused increasing operational costs. One way to solve the problem is by using a Progressive Cavity Pump (PCP) where the movement of the rotor to the stator passes through the production fluid including sand that is produced to the surface so that the pump stuck problem due to the accumulation of sand can be overcome. In addition to the ability to overcome the sand, PCP provides a high level of pump efficiency reaching up to 75%.

Keywords
Unconsolidated sand, Rate Critical, Progressive Cavity Pump, Pump Efficient, pump stuck, Stress Formation, well intervention, Overburden Formation

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/Kkg8BtP2h7j4

Corresponding Author
Ady Setya Nugroho

Institutions
Universitas Pembangunan Nasional Veteran Yogyakarta

Abstract
The typical standard geothermal well slotted liner is a 7", research on big hole slotted liner to increase steam production in geothermal fields. In the previous study the potential of geothermal field was 380 Mwe, while currently it has been produced at 39.79 Mwe, so that the field geothermal is feasible to be developed again. The current conditions there are 7 production wells with normal hole (7 "liners) that have been proven to produce continuously in developing this production will be simulated using the big-hole size slotted liner, starting at 8 5/8", 9 5/8 ", 10 ¾ ", 11 ¾", 13 3/8 "16", 20 ". With proven reservoir condition data, the geothermal field is feasible for production studies using big holes. The main parameters include Temperature, Preassure, mass flow and steam quality. The conceptual model is an interpretation of the condition of the reservoir so that the reservoir conditions in the well can be identified as data for the study. WellSim Simulator is used to predict pressure loss in the hole and bottom surface, and vice versa. The output is the pressure, mass flow rate, temperature, dryness and enthalpy of the wellhead so that various casing sizes can be simulated with the condition of the reservoir. The optimal size of the production liner developed in the geothermal field is 9 5/8 ".

Keywords
Big hole; Production; Wellsim

Topic
Petroleum and Geothermal Engineering

Link: https://ifory.id/abstract/K3z2GXBFLxwZ