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Indonesia is at the junction of three tectonic plates which play a role in forming Indonesia's volcanic mountains. This source of magma from the mountains becomes a source of heat, making Indonesia one of the countries with the largest geothermal reserves in the world. In the midst of the transition from using fossil energy to renewable energy, the development of geothermal fields has increased quite significantly. However, geothermal field locations are usually in remote areas so that conventional equipment commonly used for oil and gas fields cannot be used for exploration and production activities. Slim hole wells are the choice of Sembalun field developers, especially at Well Y. Production has continued to decline in the last two years. The field developers decided to use hydraulic fracturing with cold water injection to increase production. However, it needs to be further analyzed whether the tubular at well Y is able to withstand the load received due to the use of hydraulic fracturing. Therefore, this study focuses on analyzing the ability of slim hole wells to withstand loads due to high temperatures from geothermal reservoirs and loads due to the implementation of hydraulic fracturing, using stress analysis from three main loads such as burst, collapse and tension. This study will ultimately produce recommendations for the use of slim hole wells and solutions for the failure of wells to withstand loads. Based on the calculation results, the reservoir temperature affects the yield strength of the intermediate casing, production casing and liner to 53052.08, 49309.03, and 46177.89 psi. The calculation of the pressure on the tubular without considering the effect of axial pressure is carried out and shows that the tubing is able to withstand the pressure. Meanwhile, with the effect of axial pressure on the burst and collapse rating, the intermediate and production casing are able to withstand the collapse load, but not the burst load. Meanwhile, the liner is not able to withstand burst loads and also collapse. After that, a triaxial pressure analysis is also performed by calculating von mises equivalent. The results show that yielding occurs in all slim hole used. The incapability of Schedule 40 casing to withstand load, bringing up a recommendation to change the grade of casing to M - 65 for intermediate casing and X - 80 for production casing and liner. In addition, modification of production parameters can also be carried out to reduce the rate of geothermal production, so that slim hole wells are able to withstand the pressure received. Sensitivity on Pump Pressure, Fracture Gradient and Wall Thickness Tolerance was conducted to determine which value is allowed to be modified. [ABSTRACT FROM AUTHOR]

The increase of surface temperature as the cause of global climate change is a real threat to all living things. Increased surface temperatures are caused by heat trapped by too large CO2 concentrations in the atmosphere. Heat and electricity production activity in the economic sector is the largest source of greenhouse gas emissions. Heat and electricity production activities comprise burning coal, natural gas, and oil. Geothermal energy is one of the alternative energy solutions to reduce greenhouse gas emissions. Increased production of geothermal energy can be done by drilling new wells or by reservoir stimulation. Hydraulic fracturing is one of the methods of reservoir stimulation to increase reservoir productivity. In hydraulic fracturing there are several design parameters to consider. In this study, the sensitivity test on the parameters of proppant size, reservoir permeability, and fracturing fluid temperature will be done. The mentioned parameters will affect the optimum geometry, optimum fold of increase, and the end of the job temperature of the hydraulic fracturing operation. The research intends to provide an insight on how fracturing operation should be optimized in order to increase operational efficiency and maintain a good production with less expenditure. Based on the simulation study, it can be concluded that higher fracturing fluid temperature and using the Badger 70/140 sand as a proppant is the most suitable option to increase fracturing effectivity. [ABSTRACT FROM AUTHOR]

The issue of flow assurance has not always been a niche for oil and gas operations only. In geothermal operations, in which produced steam undergoes highly dynamic alterations in both pressure and temperature. Mechanistic modeling on flow in tubing has not been extensively used in the multiphase flow system albeit the simplicity given by the method to forsee the flow behaviour of the system. it is worth noting that the issue of flow regime change could mean production impairment or worse, possibility of well shutdown. This publication addresses the application of mechanistic modelling, manifested in Flow Pattern Map adapted from previous researches in artificial lift optimization to geothermal operations. Flow Pattern Map has been known to be reliable in optimizing gas lift operations as a function of injected gas and produced liquid. Retrofitting the FPM into geothermal requires minor conversion from volumetric flow rate to mass flow rate. This provides the incentive for detailed analysis as the function of tubing size is the eliminated in the calculation. In order to validate the concept of FPM in geothermal operations, two published case study from Tompaso Geothermal Project and Awibengkok Geothermal Project. Based on the production test results, some minor adjustments need to be applied before the FPM can be functional. Noticing the FPM is intended for certain size of tubing, the adjustment also need to be applied to the given tubing size. Nevertheless, it can be concluded that the application of FPM can be adapted into geothermal based production optimization. This study serves a simple approach on flow behavior on the geothermal system. A catalyst for more advanced analysis on geothermal flow assurance modelling will be the aim of this study. [ABSTRACT FROM AUTHOR]

Volcanic lithology reservoir, commonly encountered in the geothermal reservoir, is one of the harder types to be developed because of its highly varied porosity and permeability caused by the presence of natural fracture. One of the solutions to increase the productivity of this type of reservoir is called hydraulic fracturing. A simulation is conducted to model the hydraulic fracturing job, as well as its economic analysis for well-X which produced oil from the tuff volcanic reservoir. A new approach to designing hydraulic fracture is by using pseudo-three-dimensional (P3D) model. Simulation using the P3D model will give a more realistic fracture geometry compared to 2D model by also analyzing the rock layers above and below the pay zone. A sensitivity analysis is conducted by varying various parameters to achieve optimum NPV. If production sharing contract (PSC) is used, the optimum case can be achieved by using Jordan Unimin 20/40 as the selected proppant with maximum concentration up to 14 PPA, pump rate 12 bpm, and NPV for 5 years at 10% discount rate of US$ 140,370 with fracture length 69.9 feet and benefit-cost ratio (BCR) 2.23. However, if the gross split (GS) economic system is to be used, the optimum case is the original condition without hydraulic fracturing treatment, which gives NPV at 10% discount rate for 5 years of US$ 481,735. [ABSTRACT FROM AUTHOR]

New discoveries of oil and gas fields in Indonesia have now shifted into CO2 rich fields. The CO2 will become a major obstacle in developing the fields economically. One of the issues in developing CO2 rich fields is how to dispose the CO2 safely or even adding some value into the disposed CO2. This publication offers an alternative of disposing CO2 from CO2 rich gas fields by injecting it into oil reservoir through CO2−EOR. Despite its urgency, CO2-EOR has not been implemented on a full field scale in Indonesia due to higher price of captured CO2. Therefore, this publication proposes a cluster-based approach to reduce CO2 transportation and compression costs. Based on two gas producing fields, X and Y Field, a classification is then provided by this study to address the suitability of CO2−EOR implementation in the nearby fields. This publication is hoped to become a reference on how to develop cost-efficient CO2−EOR. [ABSTRACT FROM AUTHOR]

The existence of old wells, if used properly can increase national production, but to reactivate old wells will be a challenge, especially if the oil contained therein is classified as heavy oil, one of the techniques to increase oil recovery which is widely used in this type of oil this is steam injection, but using steam injection on a low strength casing can cause the casing to fail due to production increase, temperature differences or due to a high corrosion rate. In this Study, there are wells in the Y-field which will be reactivated using cyclic steam stimulation, these wells use K-55 tubing, so it needs to be re-evaluated in terms of tubing strength due to increased production and temperature differences when steam injected, based on the results of the evaluation of the K-55 , K-55 tubing is still able to withstand the load due to production increase but the K-55 tubing is unable to withstand the load due to temperature differences when steam is injected, while the highest corrosion rate evaluation of the K-tubing 55 is still included in the acceptable value. [ABSTRACT FROM AUTHOR]

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, Xf 76.8 ft is obtained with fracture width, wf 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. [ABSTRACT FROM AUTHOR]