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East Natuna is well known for its huge natural gas reserves with a very high CO2 content. The appearance of CO2 content in an oil and gas field is always considered as waste material and will severely affect the economic value of the field. The higher the content, the more costly the process, both technically and environmentally. In this research, the newly proposed reservoir management approach called CSSU (Carbon Sequestration Storage and Utilization) method is trying to change the paradigm of CO2 from waste material into economic materials. The novelty of this research is the combined optimization of deterministic and stochastic methods with the Particle Swarm Optimization (PSO) algorithm to answer complex and non-linear problems in the CSSU (Carbon Sequestration Storage and Utilization) method. The CSSU method is an integration of geological, geophysical, reservoir engineering and engineering economics with the determination of technical and economic optimization of the use of CO2 produced as working fluid in a power generation system that has been conditioned through an injection-production system in geological formations. The CSSU research area is located in a sedimentary basin that has a giant gas field with 70% CO2 content. The Volumetric Storage Capacity for CO2 injection process in research area is 1,749.14 BCF or 94.01 MMTon which being calculated based on static modeling considering geological, geophysical and petrophysical aspects. A combination of Compositional, Geomechanics and Thermal reservoir simulation model had been conducted to determines the Storage Injection capacity and later to prove the CSSU method in which CO2 fluids will be utilized as working fluid, 1 case was built using 2 Injection Wells and 1 CO2 fluid Production Well. The simulation results show with 1 production well the total of CO2 fluid injected from 2 Injection wells can almost double the injection total capacity up to 1,150 BCF. The utilization of supercritical CO2 fluid as working fluid can produce 55 – 133.5 MMBTU/Day or 0.67 - 1.63 MW from 1 production well for 25 years timeframe. The CSSU method is optimized by deterministic and stochastic methods using the Particle Swarm Optimization (PSO) algorithm by looking the technical and economical aspects. The technical optimization aspect is being analyzed by electricity production versus well counts. The economical optimization is being analyzed by operational expenditure saving versus well counts and electricity produced versus NPV 10%. From both aspects the 4 injector wells case and NPV 200.00 MM US$ gives the most optimum result within technically and economically. The CSSU economic model proved with CSSU scheme the economical value is being increased by 57 MMUS$ after operating cost efficiency due to the electricity savings, 92 MMUS$ due to Carbon Trading which resulting the NPV 10% is 172.77 MMUS$.

Previous laboratory studies have shown that the combination of molasses and commercially-available fertilizer (NPK and ((NH4)2HPO4) can stimulate bacterial growth that decreases oil viscosity and interfacial tension (IFT). In this project, a huff-and-puff field implementation of MEOR nutrient injection has been conducted in two selected wells in Bentayan Field, South Sumatera, BN-38, and BN-81. The project objective is to evaluate and analyze the effect of nutrient injection towards oil recovery, changes of indigenous microbes that alter oil characteristics from the two selected wells during three months of post-nutrient injection monitoring phase. Changes of oil production were measured in-line after the gross produced liquid passes through a separator unit. The abundance of aerobic, anaerobic, and sulfate-reducing bacteria (SRB) was examined by using Total Plate Count (TPC) method, while anaerobic bacteria and SRB were cultivated using the Hungate technique. The chemical compositions of the oil were analyzed before and after nutrient injection by using gas chromatography-mass spectrometry (GC-MS) method. Fluid analysis of the oil (kinematic viscosity and interfacial tension) were measured by viscometer and IFT meter. The program of nutrient injection started with 500 bbls of first nutrient injection, followed by 100 bbls of post-flush 1, 500 bbls of second nutrient injection, 100 bbls of post flush 2, soaking for 14 days, 2000 bbls post-flush 3, and soaking for seven days. Based on the results of bacterial abundance analysis for three months, there was an increase of almost 1000-fold of total aerobic bacteria abundance and 10-fold of anaerobic bacteria abundance after nutrient injection. The expansion of bacterial abundance successfully changed the physical-chemical condition of the oil, decreasing oil viscosity by approximately 24% and IFT by 47%. In both wells, water cut values were decreased from 99% to 92%, and incremental oil was gained by 1395 barrels. Huff and puff nutrient injection seems to be low-cost EOR since it can be included in the daily operating cost with the additional cost of workforce, nutrient, monitoring, and analysis. Economic analysis calculation of this project resulted in Pay-out-Time (POT) by four months with an incremental gain of approximately 1750 barrels.

During periods of low oil prices, profitability of field developments drops drastically. To help with this difficulty, we offer a cost-effective method of boosting hydrocarbon recovery by optimizing well locations. A new software program has been developed to optimize vertical well placements based on the Simulated Opportunity Index (SOI). SOI is an intelligent method to identify zones with high potential for production. The production potential of an oil & gas field area is empirically calculated from basic rock and fluid properties, and from reservoir pressure as its energy capacity. In order to obtain the best results, the original SOI formula (Molina et al., 2009) was extended to both oil and gas fields. With the new SOI software, it is possible to rank the best layers in each areal location, resulting in appropriate vertical well locations and perforated intervals in multilayer reservoirs. Furthermore, the developed software can account for the effects of existing wells and sealing faults to accommodate infill programs in brown fields and compartmentalized reservoirs. This paper describes how the software helps in obtaining optimal solutions with better accuracy than previous studies resulting in the highest recovery for three different case studies in an oil and gas field located in offshore Indonesia. The sensitivity analysis that was performed shows a strong relationship between SOI value and recovery factor. It validates that the higher SOI values selected by the software give higher recovery factors. The developed software could boost field development projects even in the period of low oil prices. On one hand, the proposed method could save money by minimizing the required number of wells. On the other hand, it could maximize profit by maximizing recovery.

Gas Flooding is one of the reservoir production management methods which commonly used in the petroleum industry in order to improve oil recoveries and maintaining reservoir pressure. This study discusses two methods in analyzing gas flooding, i.e., material balance analysis and reservoir simulation methods. The objective is to examine the ability and advantages of material balance method with respect to reservoir simulation. The studied field has three productive zones which consist of two light oil zones and one dry gas zone. Gas flooding scenario was conducted in one light oil reservoir and was modeled using both material balance and reservoir simulation methods to predict reservoir performance for about 14 years and the results were compared to investigate the effect of gas injection. The material balance method employs production, PVT, pressure data, and averaged properties of geological model for a single tank model. On the other hand, the reservoir simulation method uses a compositional model to investigate in detail the effect of injected gas to reservoir fluid behavior and the oil recovery The examinations indicate that the material balance analysis method shows the advantages of a requiring much less data, but could give reasonably accurate results. Furthermore, the application of material balance analysis in gas flooding could be used for gas injection rate optimization for a very short time manner and could assist for further development of reservoir simulation. For future development, material balance analysis could be used to analyze gas flooding scenario to save time and cost rather than reservoir simulation which takes longer time.

A gas field company concern is to seek the highest gas plateau rate as possible for a contract rate of sale gas to obtain the most economics field development scenario. On the other hand, the higher plateau rate causes more gas reserve left underground after end of the plateau rate for the rest of the life of a field, and this reserve left would be the government concern as the owner to maximize the field ultimate recovery. Having this fact, a new concept has been brought up to solve this optimization problem to find a meeting point between the two concerns by figuring the performance of the Recovery Factor (RF) at the end of the plateau rate or until the end of the contract; we name it Contractor Concern Recovery Factor (CCRF), and the performance of Remaining Recovery Factor (RFR) after the contract ends until the Field Ultimate Recovery Factor; we name it Government Concern Recovery factor (GCRF), with respect to Rate of Return (ROR), at which the two performances behave oppositely. We define this meeting point of CCRF and GCRF the optimum for both parties, a win-win solution for the gas field company as an operator and the government as the owner. Having this optimization concept, a reservoir model of a real gas field is run for a sensitivity analysis study and Design of Experiment (DoE) of important parameters for the optimum gas plateau flow rate, and the results suggest that Original Gas in Place, is the most influencing parameter followed by average permeability and gas relative permeability. Finally, a correlation is introduced by applying the Least-Square method to find a relationship between the optimum gas plateau flow rate with the parameters, and the resulted correlation has an acceptable accuracy.

This paper is a laboratory study to investigate changes in rock and fluid properties in accordance with the most important vibroseismic parameters, i.e., frequency and amplitude. Experiment are conducted to obtain porosity, permeability, capillary pressure, end point of relative permeability, residual oil saturation which represent rock properties and oil viscosity whcih represent fluid properties. The results of the laboratory study on synthetic cores indicate that vibration stimulation can improve the porosity (ϕ) up to 15.3 % and the absolute permeability (kabs) up to 2.2 %, decrease the residual oil saturation (Sor) upto 53.6 %, decrease the irreducible water saturation (Swirr) up to 25 % (decrease the capillary pressure), increase the end point of oil relative permeability (kro) up to 73 %, and increase the end point of water relative permeability (krw) up to 76 %. This study also shows that there is an optimum frequency and amplitude that yield the most significant effect. The results show that frequency of 10 Hz and the maximum amplitude yield the maximum changes in these rock properties. Experiments on sandstone-field sample cores yield that the original porosity of 4.84 % - 26.73 % and absolute permeability of 231.46 mD – 1113.59 mD can be increased in percentage as a high as 53.9 % with an average of 36.6 % from the original porosity, and as high as 54.1 % with an average of 59.4 % from the original permeability. Moreover, the original residual oil saturation varying from 0.15 % - 0.57 % can be decreased up to 68 % with an average of 66.1 %. On carbonate cores, the results are not as encouraging as for sandstones’. The resulted optimum frequencies are 15 Hz and 10 Hz for reducing the residual oil saturation, and porosity/permeability, respectively. The differences between the residual oil saturation before and after the vibration vary from 14.18% up to 54.14% at this optimum frequency. The porosity changes vary from −18% up to 42 % (cek), and permeability changes vary from −28% up to 29 % (cek angkanya). This means that the vibration could not improve or even damage the rock properties if we do not apply the correct optimum frequency. In oil viscosity investigation, for the samples that has viscosity of 0,66 cp and 1.1 cp at 1000 psig, the viscosity measurement is conducted at temperature of 70oC, 85oC and 95oC for 1000 psig, 1500 psig, 2000 psig, 2500 psig and 3000 psig. For the lower viscosity sample at temperature of 70oC, the viscosity reduction at optimum frequency and maximum amplitude is proven to be increasing with the increasing pressure, it varies from 19,38% up to 22,6%. However, for temperature 85 oC, the viscosity reduction is about 30%, and for temperature of 95oC is about 15%. The highest viscoty sample yield viscosity reduction at temperature of 85oC ranging from 27–28%. The laboratory study results on the field core prove the success of the vibration stimulation technology with caution in selecting the optimum frequency, and hopefully, it may give contribution knowledge on the mechanisms of the vibroseismic technology.

This paper presents an analytical method to predict production performance of a well producing from a solution gas-drive reservoir. Many available analytical techniques published for a solution gas-drive reservoir have been intended mainly for data analysis techniques and they were proved to be valid only for one particular flow regime (i.e., transient flow). Many have used Inflow Performance Relationship (IPR) method to predict the well performance in these reservoirs. The shortcoming of this method is that it is based on regression to either field data or numerical simulation results. The data are sampled on one particular flow regime (i.e., boundary-dominated or pseudo-steady state flow). Hence, the outcomes are highly dependent on the condition at which the data are sampled. The analytical method in this paper addresses all flow regimes (transient, transition, and boundary dominated flow). The solution also considers that all phases (oil, gas, and water) can flow. This solution is also validated with results from numerical simulation for various fluids and reservoir properties.