scholarly journals Laboratory Studies to Increase Oil Production Using Methyl Ester Sulfonate Injection on X Field

2020 ◽  
Vol 2 (3) ◽  
Author(s):  
Aditya Rachman ◽  
Rini Setiati ◽  
Kartika Fajarwati Hartono
Keyword(s):  
Methyl Ester ◽  
Oil Recovery ◽  
Oil Production ◽  
Oil Fields ◽  
Recovery Factor ◽  
Laboratory Studies ◽  
Core Flooding ◽  
Screening Parameter ◽  
Oil Formation

<em>The majority of petroleum production comes from the brown field where production has decreased from year to year in Indonesia. To increase the recovery factor of petroleum from the reservoir, an advanced step of production is required, Enhanced Oil Recovery (EOR), which can optimize the depletion of old oil fields. EOR is the application of technology that requires cost, technology and high risk. Therefore, before implementing EOR, in a field, we must carefully evaluate both technically and economically to obtain an optimal additional recovery. This research was conducted to increase oil production by injection of Methyl Ester Sulfonate (MES). This study begins with a screening parameter crude oil, formation water, Berea’s core, and determination of phase behavior, interfacial tension (IFT), thermal stability, imbibition, and core flooding tests. The result for concentratin optimum in 0.3% MES and had IFT 0.3267 dyne/cm. The results of core flooding tests are: Recovery factor of waterflooding is 33.95 % and recovery factor of MES injection is 4.19 %.</em>

Oil production facilities management improving using the analogy method

2020 ◽  
pp. 42-50
Author(s):  
V.V. Mukhametshin ◽  
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Geological Structure ◽  
Oil Fields ◽  
Facilities Management ◽  
Analogy Method ◽  
Oil Reserves ◽  
High Degree ◽  
Production Facilities

For the conditions of an oil fields group characterized by an insufficiently high degree of oil reserves recovery, an algorithm for objects identifying using parameters characterizing the objects’ geological structure and having a predominant effect on the oil recovery factor is proposed. The proposed algorithm allows us to substantiate and use the analogy method to improve the oil production facilities management efficiency by targeted selection of the information about the objects and processes occurring in them, removing uncertainties in low density conditions, the emergence of real-time decision-making capabilities, determination of optimal ways of current problems solving, reducing the probability of erroneous decisions making, justifying the trend towards the goals achieving.

Low-Cost Development Plan Optimization for a Polish Oil Field

2021 ◽  
Author(s):  
Daniel Podsobinski ◽  
Roman Madatov ◽  
Bartlomiej Kawecki ◽  
Grzegorz Paliborek ◽  
Piotr Wójcik ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Capital Expenditure ◽  
Oil Production ◽  
Oil Field ◽  
Oil Fields ◽  
Development Plan ◽  
Recovery Factor ◽  
Co2 Injection ◽  
Development Scenarios ◽  
Injection Water

Abstract In Poland there are approximately 60 oil fields located in different geological structures. Most of these fields have been producing for several years to several dozen years, and now require redefining of the development plan by utilizing an improved oil recovery (IOR) or enhanced oil recovery (EOR) method to achieve a higher oil recovery factor. Here we present the redevelopment plan for the Polish Main Dolomite oil field, that aimed to optimize and maximize the oil recovery factor. Considering all available geological and reservoir data, both a static and dynamic model were built and calibrated for three separate reservoirs connected to the same production facility. Then the comprehensive study was performed where different development scenarios was considered and tested using reservoir numerical simulation. The proposed redevelopment scenarios included excessive gas reinjection to the main reservoir, additional high-nitrogen (N2) gas injection from a nearby gas reservoir (87% of N2), carbon dioxide (CO2) injection, water injection, polymer injection, water-alternating-gas (WAG), well stimulation, and a combination of these methods. Development plans assumes also drilling new injection and production wells and converting existing producers to gas or water injectors. The key component in development scenarios was to arrest the pressure decline from the main field and decrease the gas/oil ratio (GOR). An additional challenge was to implement in the simulation model all key assumptions behind various development scenarios, while also taking into account specific facility constraints and simultaneously handling separate reservoirs that are connected to the same facility, and hence affecting each other. From numerous scenarios, the scenario that requires the least number of new wells was selected and further optimized. It considers the drilling of only one new producer, one new water injector, and conversion of some currently producing wells to gas and water injectors. The location of the proposed well and the amount of injection fluids was optimized to achieve the highest oil recovery factor and to postpone gas and water breakthrough as much as possible. The optimized case that assumes low investments is expected to improve incremental oil production by 90% over No Further Actions Scenario. However, the study suggests the potential of more than tripling incremental oil production under a scenario with considerably higher expenditures. The improved case assumes drilling one more producer, four new water injectors, and injection of three times more water. The presented field optimization example highlights that in many existing Polish oil fields there is still a potential to reach higher oil recovery without considerable expenditures. However, to obtain more significant oil recovery improvement, higher capital expenditure is necessary. To facilitate the selection of the best development scenario, a detailed economic and risk analysis needs to be conducted.

scholarly journals OPTIMIZATION OF SURFACTANT FLOODING ON BJG FIELD USING DYNAMIC PATTERN

PETRO ◽  
2020 ◽  
Vol 9 (2) ◽  
pp. 52
Author(s):  
Ajeng Purna Putri Oktaviani ◽  
Leksono Mucharam
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Real Data ◽  
Cost Effective ◽  
Oil Fields ◽  
Recovery Factor ◽  
Surfactant Flooding ◽  
Spot Pattern ◽  
Dynamic Pattern ◽  
Mature Field

<em>Mature fields, also known as brownfields, are fields that are in a state of declining production or reaching the end of their production lives.  Development of mature oil fields has been, and will increasingly be, an exciting subject (Babadagli, 2007). New studies already discovered innovative ways of finding, developing, and producing hydrocarbons that are efficient and cost-effective and minimize harm to the environment. BJG Field is one of the mature fields which is produced in 1927, one of the efforts for enhancing the production is using waterflood at the beginning of 2001. To increase production further, then we need to conducted studies as an application of the second recovery from BJG Field. The oil recovery factor BJG field can be increased using a surfactant flooding scenario. This research aimed to conduct a study of dynamic pattern surfactant flooding using simulations as applicable for the mature field. The research is expected to obtain an optimum surfactant injection scenario using IMEX and STARS simulator. Simulation is done with real data from the BJG field, and the result has shown the scenario which has the most significant oil production. The highest recovery factor is the chosen scenario. From the results of studies and simulation shown that dynamic pattern inverted five-spot pattern can be used. The increment of oil recovery factor is 32.29% from the waterflood case.</em>

Determination of Optimum Parameters for Anaerobic Thermophilic Bacterium Injection using Commercial Simulator: Core Flooding Validation and Sensitivity

2020 ◽  
Author(s):  
A. Koto
Keyword(s):  
Oil Recovery ◽  
Simulation Experiment ◽  
Previous Experiment ◽  
Core Sample ◽  
Thermophilic Bacterium ◽  
Injection Rate ◽  
Core Flooding ◽  
Optimum Parameters ◽  
Result Show

The objective of this paper is to determine the optimum anaerobic-thermophilic bacterium injection (Microbial Enhanced Oil Recovery) parameters using commercial simulator from core flooding experiments. From the previous experiment in the laboratory, Petrotoga sp AR80 microbe and yeast extract has been injected into core sample. The result show that the experiment with the treated microbe flooding has produced more oil than the experiment that treated by brine flooding. Moreover, this microbe classified into anaerobic thermophilic bacterium due to its ability to live in 80 degC and without oxygen. So, to find the optimum parameter that affect this microbe, the simulation experiment has been conducted. The simulator that is used is CMG – STAR 2015.10. There are five scenarios that have been made to forecast the performance of microbial flooding. Each of this scenario focus on the injection rate and shut in periods. In terms of the result, the best scenario on this research can yield an oil recovery up to 55.7%.

Pilot Project Evaluating WAG Efficiency for Carbonate Reservoir in Eastern Siberia

2021 ◽  
Author(s):  
Valentina Zharko ◽  
Dmitriy Burdakov
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Pilot Project ◽  
Carbonate Reservoir ◽  
Recovery Factor ◽  
Eastern Siberia ◽  
Water Cut ◽  
Wag Injection ◽  
Injection Rates

Abstract The paper presents the results of a pilot project implementing WAG injection at the oilfield with carbonate reservoir, characterized by low efficiency of traditional waterflooding. The objective of the pilot project was to evaluate the efficiency of this enhanced oil recovery method for conditions of the specific oil field. For the initial introduction of WAG, an area of the reservoir with minimal potential risks has been identified. During the test injections of water and gas, production parameters were monitored, including the oil production rates of the reacting wells and the water and gas injection rates of injection wells, the change in the density and composition of the produced fluids. With first positive results, the pilot area of the reservoir was expanded. In accordance with the responses of the producing wells to the injection of displacing agents, the injection rates were adjusted, and the production intensified, with the aim of maximizing the effect of WAG. The results obtained in practice were reproduced in the simulation model sector in order to obtain a project curve characterizing an increase in oil recovery due to water-alternating gas injection. Practical results obtained during pilot testing of the technology show that the injection of gas and water alternately can reduce the water cut of the reacting wells and increase overall oil production, providing more efficient displacement compared to traditional waterflooding. The use of WAG after the waterflooding provides an increase in oil recovery and a decrease in residual oil saturation. The water cut of the produced liquid decreased from 98% to 80%, an increase in oil production rate of 100 tons/day was obtained. The increase in the oil recovery factor is estimated at approximately 7.5% at gas injection of 1.5 hydrocarbon pore volumes. Based on the received results, the displacement characteristic was constructed. Methods for monitoring the effectiveness of WAG have been determined, and studies are planned to be carried out when designing a full-scale WAG project at the field. This project is the first pilot project in Russia implementing WAG injection in a field with a carbonate reservoir. During the pilot project, the technical feasibility of implementing this EOR method was confirmed, as well as its efficiency in terms of increasing the oil recovery factor for the conditions of the carbonate reservoir of Eastern Siberia, characterized by high water cut and low values of oil displacement coefficients during waterflooding.

Enhanced Oil Recovery Application of Nanoparticles in Niger Delta Water-Wet Reservoir Rock

2021 ◽  
Author(s):  
Tinuola Udoh
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Core Samples ◽  
Recovery Potential ◽  
Secondary Formation ◽  
Injection Modes

Abstract In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.

Laboratory studies of oil-washing characteristics of surfactants in the pore space of reservoir rocks

2021 ◽  
pp. 86-98
Author(s):  
V. Yu. Ogoreltsev ◽  
S. A. Leontiev ◽  
A. S. Drozdov
Keyword(s):  
Oil Recovery ◽  
Pore Space ◽  
Oil Field ◽  
Oil Fields ◽  
Molecular Surface ◽  
Laboratory Studies ◽  
Reservoir Rocks ◽  
Technological Efficiency ◽  
Chemical Eor ◽  
Physical And Chemical

When developing hard-to-recover reserves of oil fields, methods of enhanced oil recovery, used from chemical ones, are massively used. To establish the actual oil-washing characteristics of surfactant grades accepted for testing in the pore space of oil-containing reservoir rocks, a set of laboratory studies was carried out, including the study of molecular-surface properties upon contact of oil from the BS10 formation of the West Surgutskoye field and model water types with the addition of surfactants of various concentrations, as well as filtration tests of surfactant technology compositions on core models of the VK1 reservoir of the Rogozhnikovskoye oil field. On the basis of the performed laboratory studies of rocks, it has been established that conducting pilot operations with the use of Neonol RHP-20 will lead to higher technological efficiency than from the currently used at the company's fields in the compositions of the technologies of physical and chemical EOR Neonol BS-1 and proposed for application of Neftenol VKS, Aldinol-50 and Betanol.

scholarly journals The efficiency of gas injection into low-permeability multilayer hydrocarbon reservoirs

2021 ◽  
Vol 3 (10) ◽  
pp. 100-108
Author(s):  
Sudad H AL-Obaidi ◽  
Miel Hofmann ◽  
Falah H. Khalaf ◽  
Hiba H. Alwan
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Recovery Factor ◽  
Low Permeability ◽  
Compositional Model ◽  
Multistage Hydraulic Fracturing ◽  
Low Permeability Reservoirs ◽  
Working Agent

The efficiency of gas injection for developing terrigenous deposits within a multilayer producing object is investigated in this article. According to the results of measurements of the 3D hydrodynamic compositional model, an assessment of the oil recovery factor was made. In the studied conditions, re-injection of the associated gas was found to be the most technologically efficient working agent. The factors contributing to the inefficacy of traditional methods of stimulating oil production such as multistage hydraulic fracturing when used to develop low-permeability reservoirs have been analyzed. The factors contributing to the inefficiency of traditional oil-production stimulation methods, such as multistage hydraulic fracturing, have been analysed when they are applied to low-permeability reservoirs. The use of a gas of various compositions is found to be more effective as a working agent for reservoirs with permeability less than 0.005 µm2. Ultimately, the selection of an agent for injection into the reservoir should be driven by the criteria that allow assessing the applicability of the method under specific geological and physical conditions. In multilayer production objects, gas injection efficiency is influenced by a number of factors, in addition to displacement, including the ratio of gas volumes, the degree to which pressure is maintained in each reservoir, as well as how the well is operated. With the increase in production rate from 60 to 90 m3 / day during the re-injection of produced hydrocarbon gas, this study found that the oil recovery factor increased from 0.190 to 0.229. The further increase in flow rate to 150 m3 / day, however, led to a faster gas breakthrough, a decrease in the amount of oil produced, and a decrease in the oil recovery factor to 0.19 Based on the results of the research, methods for stimulating the formation of low-permeability reservoirs were ranked based on their efficacy.

scholarly journals A Laboratory Approach on the Hybrid-Enhanced Oil Recovery Techniques with Different Saline Brines in Sandstone Reservoirs

Processes ◽  
2020 ◽  
Vol 8 (9) ◽  
pp. 1051 ◽  
Author(s):  
Yisheng Hu ◽  
Qiurong Cheng ◽  
Jinping Yang ◽  
Lifeng Zhang ◽  
Afshin Davarpanah
Keyword(s):  
Oil Recovery ◽  
Foam Stability ◽  
Oil Production ◽  
Mobility Control ◽  
Recovery Factor ◽  
Wettability Alteration ◽  
Bulk Solution ◽  
Formation Water ◽  
Sandstone Reservoirs ◽  
Brine Injection

As foams are not thermodynamically stable and might be collapsed, foam stability is defined by interfacial properties and bulk solution. In this paper, we investigated foam injection and different salinity brines such as NaCl, CaCl2, KCl, and MgCl2 to measure cumulative oil production. According to the results of this experiment, it is concluded that sequential low-salinity water injections with KCl and foam flooding have provided the highest cumulative oil production in sandstone reservoirs. This issue is related to high wettability changes that had been caused by the KCl. As K+ is a monovalent cation, KCl has the highest wettability changes compared to other saline brines and formation water at 1000 ppm, which is due to the higher wettability changes of potassium (K+) over other saline ions. The interfacial tension for KCl at the lowest value is 1000 ppm and, for MgCl2, has the highest value in this concentration. Moreover, the formation brine, regarding its high value of salty components, had provided lower cumulative oil production before and after foam injection as it had mobilized more in the high permeable zones and, therefore, large volumes of oil would be trapped in the small permeable zones. This was caused by the low wettability alteration of the formation brine. Thereby, formation water flowed in large pores and the oil phase remained in small pores and channels. On the other hand, as foams played a significant role in the mobility control and sweep efficiency, at 2 pore volume, foam increased the pressure drop dramatically after brine injection. Consequently, foam injection after KCl brine injection had the maximum oil recovery factor of 63.14%. MgCl2 and formation brine had 41.21% and 36.51% oil recovery factor.

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