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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]

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]

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]

Gas lift is one of the most popular artificial lift methods available in the oil and gas industry. It relies on reducing fluid density, henceforth reducing the pressure gradient along the wellbore and eventually enables liquid to be lifted at ease. As Indonesia's oil fields are reaching mature state, optimization in artificial lift method is one of the most feasible actions and it carries lower risk compared to injecting foreign substance into the reservoir. Previous efforts in optimizing gas lift design has been revolving around the application of Gas Lift Performance (GLP) curves, where changes in oil recovery is monitored as a function of gas injected. As established as this method nowadays, it still carries a heavy burden when dynamic pressure and rate changes should accounted in a very small time step. Therefore, the application of mechanistic modeling can be an alternative to reduce complexity in modeling dynamic GLP curves. This research presents a novel extension of Flow Pattern Map (FPM) as a function of tubing size in order to map optimum injection gas rate. A new correlation is also presented as a correction factor for highly utilized tubing sizes in oil and gas industry, therefore increasing the versatility of FPM application in gas lift optimization. [ABSTRACT FROM AUTHOR]

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 economic value to the project. Utilization of this method increases the NPV of the project by 10.4% and 12% increase in RF. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Locating a horizontal well to maximize a gas field production requires not only a right direction but also horizontal segment length. This is due to the longest segment does not necessarily give the maximum gas production, and each direction has its own optimum segment length. Currently, this problem is solved through a trial and error method. This method requires significant efforts and time to find the best location in order to provide a good reservoir model. In this study, a new construction of an optimization problem for optimizing gas production is proposed. Genetic Algorithm is applied to avoid the trial and error procedure. A set of two consecutive objective functions is constructed, i.e., one which is based on the quality of basic reservoir rock properties resulted from summing of all the grids of objective function values in a chosen direction, and the second one which is derived from a curve fitting cubic spline function of the cumulative gas production at a plateau time period with respect to the horizontal well length. This is resulted from only few runs of the conventional reservoir simulation method. In conclusion, using a newly proposed objective function we can produce much faster and reliable results compared with results obtained from the conventional trial and error reservoir simulation technique. This study yields a direction of 348°, and horizontal segment of 536.5 meter resulting in 7.06 years of plateau time with error of 1.133%. Furthermore, an economic evaluation was conducted by using the resulted gas production profiles corresponding to horizontal well directions and horizontal length obtained from the reservoir simulation. [ABSTRACT FROM AUTHOR]