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Ristiyan Ragil Putradianto
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Journal of Petroleum and Geothermal Technology
Published by Universitas Pembangunan Nasional Veteran Yogyakarta
ISSN : 27230988     EISSN : 27231496     DOI : https://doi.org/10.31315/jpgt.v1i1
Core Subject : Science, Engineering,
Earth & Planetary Sciences Energy Engineering
Journal of Petroleum and Geothermal Technology (JPGT) is a journal managed by Petroleum Engineering Department, Universitas Pembangunan Nasional "Veteran" Yogyakarta. This Journal focuses on the petroleum and geothermal engineering including; reservoir engineering, drilling engineering and production engineering.
Arjuna Subject : Teknik (semua kategori) - Teknik (Lain-Lain)
Articles 39 Documents
 1   2   3   4 
HYDRAULIC FRACTURING ANALYSIS OF LOW PERMEABILTY, HEAVY OIL RESERVOIR TELISA FORMATION, BENTAYAN FIELD Amril Anshary
Journal of Petroleum and Geothermal Technology Vol 3, No 2 (2022): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v3i2.7197

Abstract

There is no proven economic oil production yet from Bentayan’s part of Telisa Layer. However, open hole log from some wells in Bentayan field indicates hydrocarbon presence in TELISA in Bentayan field. GGR study also indicated low value in permeability of Telisa in Bentayan field. Production test in BN-62 indicates oil presence from Telisa with very low influx. To prove the hydrocarbon prospect of Telisa in Bentayan field, operator planned to develop Telisa in BN-62 and BN-21 by conducting hydraulic fracturing using approximately 80,000 lbs of proppant.Early screen out happened when fracturing both wells. After the job, these two wells could not prove economical hydrocarbon production from Telisa. Both wells only have AOFP of 3 BFPD with lack of hydrocarbon indication.Evaluation indicated that the cause this failure on the fracturing job may be caused by smaller value of flow efficiency than it was predicted due to the large permeability zones and formation of multiple fractures that caused pad volume and the slurry pumping flow rate to be less to create the expected fracture geometry. Based on rock property map, BN-95 is suggested to be a candidate to prove the prospect of economical hydrocarbon content in from Telisa. Keywords: well stimulation, hydraulic fracturing, low permeability reservoir, Telisa  
Sand Problem Handling Strategy On Well Ar-02 With Hydraulic Pumping Unit Ayu Regita Pramesti; Nur Suhascaryo; Boni Swadesi
Journal of Petroleum and Geothermal Technology Vol 3, No 2 (2022): November
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v3i2.7279

Abstract

AR-02 well is one of the oil production wells located in Structure X. This well is produced using the Hydraulic Pumping Unit (HPU) method due to low reservoir pressure as a result of the reduced production capacity of the Y Field formation. In addition, this well has sand problems because the fluid production rate of 96 bfpd exceeds the critical sand flow rate of 66.81 bfpd. The physical properties of reservoir rocks do not cause sand problems because they have a cementation factor of highly cemented (m = 1.99), relatively small clay content (5.4%), compact rock (∆t = 54.16 s/ft), and compact as well as stable formation rock (G/Cb = 14.85x1012 psi2). In solving the sand problem in the AR-02 Well, the Gravel Pack and screen were installed. The correct Gravel size according to the Saucier method is 0.035 inch and the correct screen size according to the Coberly & Wagner, Tauch & Corley, and H. J. Ayre methods is 0.016 inch. The value (G-S) ratio indicates that the selection of Gravel and screen sizes is correct (stable), namely the value (G-S) ratio is at number 5. Redesign of the production scheme due to the installation of the Gravel Pack with the use of HPU pumps at the same setting produces; P due to Gravel installation 40 psi, qfluid after Gravel installation 90 bfpd (previously 95 bfpd), PI after Gravel installation 0.188 (previously 0.198), Min allowable stress 8991.56 psi, Max allowable stress 23420.64 psi, Total stretch 55.42 inch, Over travel 0.391 inch, Plunger stroke 94.97 inch, and Pump Displacement 135.65 bfpd.
Evaluation of Propellant/Stimgun Stimulation Works Using Geomechanical Analysis Based on Well Logging Data in an Effort to Increase Production at the EYP-211 YNK Structure Well in the Jambi Field Eko Yugi Priyatno
Journal of Petroleum and Geothermal Technology Vol 4, No 1 (2023): May
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i1.7771

Abstract

The oil production flow rate of the EYP-211 well is relatively small, only 12.75 BOPD. The small fluid flow rate is caused by the small formation permeability which is only 2.1 mD. Currently the EYP-211 well has been stimulated with Propellant/Stimgun, but not all of the formation layers can be carried out by Stimgun work so that it is necessary to evaluate it with Geomechanical analysis to determine the success of the stimulation work by calculating the Poisson's ratio and Young's modulus which will be analyzed based on well-logging data.Based on the results of the brittleness index and fracability index analysis, the EYP-211 well is recommended to be stimulated at a depth of 632.92 m to 635.46 m. Stimgun work on the EYP-211 well resulted in a fracture with an average fracture width of 0.02035 in, a fracture height of 9.81 ft and a fracture length of 481.09 ft. The formation permeability increased from 2.1 mD to 14.07 mD due to fractures produced by the stimulus. The flow rate of oil production in the EYP-211 well increased from 12.75 bopd to 140 bopd due to the increased permeability generated by the fracture.
Flow Assurance Improvement by Injecting Pour Point Depressant Chemical through Permanent Coiled Tubing Gas Lift to Heavy Oil at MM-1 Well at MPA Field sebastianus riskadarto; harry budiharjo sulistyarso; nur suhascaryo
Journal of Petroleum and Geothermal Technology Vol 4, No 1 (2023): May
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i1.8717

Abstract

The majority artificial lift used in MPA Field use PCTGL (Permanent coil tubing gas lift). PCTGL is installed on several monobore well or dual monobore well. Some wells in the MPA Field have waxy HPPO oil character with pour point between 85-100oF with API between 30-35. The well "MM-1" has a HPPO character with pour point 95oF. The character high Pour point oil of the well will be problem to be solved. The MM-1 well is produced with PCTGL. From the simulation, a PCTGL design was obtained at a depth of 2250 ft. With the character of HPPO oil, pour point depressant injection optimization is also carried out along with the injection of gas lift so that the chemical can work from the downhole. The results of the bottle test of pour point depressant use concentration of 1000 ppm to reach the target. The results of the field test showed that the concentration of Pour Point Depressant of 1026 ppm was able to change the pour point up to 65oF. The results of optimization production showed that the production of MM-1 wells was able to increase with production of 290 bopd.
Technical and Economical Study on Increasing Oil Production in Old Wells (Traditional) by Performing Well Maintenance in the CP Field Ardi Alfarizi; Nur Suhascaryo; Boni Swadesi
Journal of Petroleum and Geothermal Technology Vol 4, No 1 (2023): May
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i1.7422

Abstract

The CP field is an brown field with a production potential of 2,185 BOPD. However, the realization of CP Field production in the first semester was 1,931 BOPD (88.4% of the production target). From Low & Off data for the period from January to September 2020, it was found that the biggest problem contributing to LPO (Lost Production Opportunity) was caused by artificial lift wells and reduced production from old (traditional) wells.Several solutions can be done in order to solve the problem. Among them is by carrying out well maintenance, both those experiencing a decline in production or wells that have the potential to be activated. By implementing this, it is hoped that it will be able to maintain stability and even increase oil production and distribution through the old (traditional) well. The screening of reactivation well candidates is carried out with the technical evaluation stage and the economic evaluation stage. The engineering evaluation was carried out by analyzing the history of well production and analyzing the distribution map of the wells in the CP Field. Based on this data, 2 (two) candidate wells were obtained, namely LDK-38 and LDK-108. Then proceed with carrying out technical calculations of Rig capacity, namely by calculating Lifting Loads, Rotating Loads and Circulating Loads and continuing with the preparation of reactivation programs and economic calculations.Based on these calculations, it was found that the need for the Rig Capacity to carry out the reactivation work of the 2 (two) wells was 21 (twenty one) HP, so the Spindle Rig was chosen to do the work because the cost was more economical, which was Rp. 45,000,000, - for the work. per-well reactivation. Therefore, the total cost required for the reactivation of 2 (two) wells is Rp. 90,000,000,-. The reactivation program for the LDK-38 and LDK-108 wells resulted in additional production in the CP Field of + 21.73 BOPD or 5,932 bbl (January - September 2021). In addition, gross revenue of USD 572,000 was obtained (crude oil price of 49 USD/bbl).
Evaluation Of Drill Bit Selection On Basement Layer Exploration Drilling In AFM Block Afi Maulana; Aris Buntoro; Dedy Kristanto
Journal of Petroleum and Geothermal Technology Vol 4, No 1 (2023): May
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i1.7176

Abstract

In one of the exploration drilling of the AF-01 well, there was a drilling problem on the 8 in hole when it penetrated the basement layer. ROP at the time of drilling the basement layer is far below the estimated ROP.By setting MSE as, ROP is increased so that cost savings are obtained from reducing rig time. A qualitative analysis of drillbit selection was carried out based on the type and design of the drillbit as well as the characteristics of the basement rock to be penetrated.In addition to the qualitative and quantitative assessment was carried out through the calculation of the PDC Design Index, MSE, DSE and CPF on each drill bit.ROP of Hybrid PDC-1 increased 500% when compared to PDC-1. The MSE and DSE produced by the Hybrid PDC-1 are 750% smaller than the PDC-1. Using the Hybrid PDC-1, drilling costs can be reduced up to USD 2,105,481.The low ROP at the time of drilling the basement layer in well AF-01 was due to the incompatibility of the PDC-1 bit used for the type of rock being penetrated. Hybrid PDC-1 is the most optimum bit to penetrate the basement layer in the AFM Block.
Heat Loss and Cost Reduction of Insulation Materials on Geothermal Pipes Ristiyan Ragil Putradianto; Allen Haryanto Lukmana
Journal of Petroleum and Geothermal Technology Vol 4, No 1 (2023): May
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i1.9706

Abstract

Power plant in X field has 6 production wells with steam dominated reservoir type. Fluid flowing in pipe from the well to the plant experienced heat loss that occured due to difference in the temperature of the flowing steam and the outside that caused heat transfer from inside the pipe to the outside. Minimizing heat transfer can be done by using an insulator is installed on the outside of the pipe, in this case, Foamglas W+F Insulation  The method to assess the heat loss is by calculating material properties as well as fluid properties to deterimine heat transfer rate for one well as representation of all wells. From the calculation, it can be concurred that the use of Foamglas W+F Insulation material provides reduction in heat loss of 113,61 kWh for one well with significant reduction in costs of 1.035 billion IDR per well per year. By comparing the heat loss reduction value which is almost the same, the option to replace the materials to Foamglas W+F insulation material is cheaper than adding the existing insulation thickness.
ACIDIZING EVALUATION OF CARBONATE ROCK IN BDA-F WELL, JATIBARANG FIELD Andri Widyanata
Journal of Petroleum and Geothermal Technology Vol 4, No 1 (2023): May
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i1.7335

Abstract

Acidizing is a dissolving activity, whether it is dissolving rock formations or other materials (natural or foreign) in reservoir of the rock. To maintain production in the Jatibarang field, especially in Bangodua (BDA) structure, there are 1 well that have experienced a short decline in production since drilling. The reservoir properties of that well is not good and there is impurity material (damage). Thus, requiring stimulation in the form of matrix acidizing. Evaluation of the matrix acid work in this well, is required for the same activities in other wells.To restore productivity this well, data were collected starting from production data, reservoir data, and well composition data. Then, candidate analysis and matrix acidizing job design are carried out. The design stage will be brought to the execution of matrix acidizing in the field. Then an evaluation was carried out after the presence of matrix acidizing in this wellThis well carried out matrix acidizing activities, produced oil production gains. BDA-F well produced with artificial lift of Electrical submersible pump – ESP in C1 layer (1128 – 1130.5 mMD), experienced an increase in test production from 749 BLPD to 1865 BLPD with a decrease in skin factor from +32 to -1.
Mineralogy and Rock Response Analysis Approach to Mitigate Wellbore Stability issue in “B” Cluster of East Java Field Andi Andi Andi
Journal of Petroleum and Geothermal Technology Vol 4, No 1 (2023): May
Publisher : Universitas Pembangunan Nasional "Veteran" Yogyakarta

Show Abstract | Download Original | Original Source | Check in Google Scholar | DOI: 10.31315/jpgt.v4i1.7336

Abstract

The instability of shales in drilled formations leads to serious operational problems with major economic consequences for petroleum exploration and production. It is generally has agreed that the nature of the clay minerals in shale formations is a primary causative factor leading to their instability, although the exact mechanism involved is more debatable. Currently, the principal cause of shale instability is considered to be volume expansion following the osmotic swelling of sodium smectite. However, illitic and Kaolinite shales may also be unstable, so that interlayer expansion cannot therefore be consider as a universal causative mechanism of shale instability. This review considers alternative scenarios of shale instability where the major clay minerals Kaolinite suspected to be a key success to mitigate the wellbore stability. It is found from the literature that the inhibited by the use of more concentrated Potassium-based fluids which is effectively shrink the thickness of the clay mineral surfaces in the pore walls but may differently responded by Kaolinite dominant clay. The use of soluble polymers would also encapsulate these clay mineral surfaces and so inhibit their hydration. In this scenario, the locus of action with respect to shale instability and its inhibition is moved from the interlamellar space of the smectitic clays to the charged external surfaces of the various clay minerals bounding the walls of the shale pores. Keywords: shale instability, smectitic shale, illitic shale, Kaolinitic shale.

Page 4 of 4 | Total Record : 39

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