DEVELOPMENT AND FIELD EVALUATION OF A NEW MICROBIAL EOR CONCEPT

1991 ◽  
Vol 31 (1) ◽  
pp. 386 ◽  
Author(s):  
Alan J. Sheehy
Keyword(s):  
Oil Recovery ◽  
Extreme Environments ◽  
Petroleum Reservoirs ◽  
Oil Production ◽  
Field Evaluation ◽  
Growth Potential ◽  
Experimental Systems ◽  
Environmental Extremes ◽  
Oil Water ◽  
Over 40 Years

For over 40 years it has been speculated that bacteria can facilitate, increase or extend oil production from petroleum reservoirs. This speculation was supported in the laboratory by dramatic increases in oil recovered from experimental systems and in the field by anecdotal accounts of improvements in oil production. Most of these studies were poorly conceived and inadequately controlled. This drew industry criticism and created an environment where proposals to implement microbiologically enhanced oil recovery (microbial EOR) were summarily dismissed. The program implemented for the Alton Field, Surat Basin, was designed to overcome industry scepticism and document unambiguously in the field the effectiveness of a new microbial EOR strategy called Biological Stimulation of Oil production (BOS). An approximate 40 per cent increase in oil production has been sustained, compared to control operations on the same well, for eighteen months.The thrust to introduce pilot and field programs of BOS is compelling. BOS shares the advantages common to all biotechnologies in exploiting the extraordinary growth potential of microorganisms, providing flexibility through the extreme diversity of microbial metabolites and using cheap feedstocks. The BOS process generates ultramicrocells from those bacteria present naturally in the reservoir to be treated. This promotes injectivity, dispersion and persistence of the BOS system in the extreme environments which characterise petroleum reservoirs. The nutrients injected with the ultramicrocells result in metabolites forming within the bacterial cell surface. These metabolites cause re-profiling of the formation through the generation of emulsions and the development of concentrated surfactants at the oil-water interface.Ecological strategies designed to negate previously documented problems in the application of microbial EOR have been shown to be effective in laboratory experiments and field applications. Overcoming environmental extremes and developing persistence of beneficial organisms have been given special attention.

scholarly journals Water Injection for Oil Recovery in Mishrif Formation for Amarah Oil Field

2020 ◽  
Vol 21 (1) ◽  
pp. 39-44
Author(s):  
Ayat Ahmed Jassim ◽  
Abdul Aali Al-dabaj ◽  
Aqeel S. AL-Adili
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Petroleum Reservoirs ◽  
Oil Production ◽  
Oil Field ◽  
Reservoir Pressure ◽  
Vertical Wells ◽  
First Case ◽  
New Ideas

The water injection of the most important technologies to increase oil production from petroleum reservoirs. In this research, we developed a model for oil tank using the software RUBIS for reservoir simulation. This model was used to make comparison in the production of oil and the reservoir pressure for two case studies where the water was not injected in the first case study but adding new vertical wells while, later, it was injected in the second case study. It represents the results of this work that if the water is not injected, the reservoir model that has been upgraded can produce only 2.9% of the original oil in the tank. This case study also represents a drop in reservoir pressure, which was not enough to support oil production. Thus, the implementation of water injection in the second case study of the average reservoir pressure may support, which led to an increase in oil production by up to 5.5% of the original oil in the tank. so that, the use of water injection is a useful way to increase oil production. Therefore, many of the issues related to this subject valuable of study where the development of new ideas and techniques.

scholarly journals Regulation of interphase processes by surfactants and their compositions in the development of oil recovery technology

2019 ◽  
Vol 55 (3) ◽  
pp. 352-358
Author(s):  
O. N. Opanasenko ◽  
N. P. Krutko ◽  
O. V. Luksha ◽  
O. L. Zhigalova
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Oil Production ◽  
Ionic Surfactants ◽  
Surface Phenomena ◽  
Innovative Technologies ◽  
Interfacial Processes ◽  
Rock Interface ◽  
Oil Water

Physicochemical aspects of the regulation of interfacial processes occurring at the oil-water-rock interface in the presence of ionic surfactants and their compositions are considered with the goal of developing efficient, scientifically grounded innovative technologies ensuring enhanced oil recovery and refining. A complex of studies of surface phenomena in the presence of ionic surfactants made it possible to identify criteria for evaluating the effectiveness of their action at the oil-water-rock interface, which makes it possible to predict the behavior of surfactants in real conditions of oil production and to use them purposefully in various enhanced oil recovery technologies.

scholarly journals Mechanism of active silica nanofluids based on interface-regulated effect during spontaneous imbibition

2021 ◽  
Author(s):  
Xu-Guang Song ◽  
Ming-Wei Zhao ◽  
Cai-Li Dai ◽  
Xin-Ke Wang ◽  
Wen-Jiao Lv
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Dynamic Contact Angle ◽  
Liquid Interface ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Low Permeability ◽  
Oil Water ◽  
Solid Liquid

AbstractThe ultra-low permeability reservoir is regarded as an important energy source for oil and gas resource development and is attracting more and more attention. In this work, the active silica nanofluids were prepared by modified active silica nanoparticles and surfactant BSSB-12. The dispersion stability tests showed that the hydraulic radius of nanofluids was 58.59 nm and the zeta potential was − 48.39 mV. The active nanofluids can simultaneously regulate liquid–liquid interface and solid–liquid interface. The nanofluids can reduce the oil/water interfacial tension (IFT) from 23.5 to 6.7 mN/m, and the oil/water/solid contact angle was altered from 42° to 145°. The spontaneous imbibition tests showed that the oil recovery of 0.1 wt% active nanofluids was 20.5% and 8.5% higher than that of 3 wt% NaCl solution and 0.1 wt% BSSB-12 solution. Finally, the effects of nanofluids on dynamic contact angle, dynamic interfacial tension and moduli were studied from the adsorption behavior of nanofluids at solid–liquid and liquid–liquid interface. The oil detaching and transporting are completed by synergistic effect of wettability alteration and interfacial tension reduction. The findings of this study can help in better understanding of active nanofluids for EOR in ultra-low permeability reservoirs.

scholarly journals Simultaneous lipid biosynthesis and recovery for oleaginous yeast Yarrowia lipolytica

2019 ◽  
Vol 12 (1) ◽  
Author(s):  
Pratik Prashant Pawar ◽  
Annamma Anil Odaneth ◽  
Rajeshkumar Natwarlal Vadgama ◽  
Arvind Mallinath Lali
Keyword(s):  
Yarrowia Lipolytica ◽  
Oil Recovery ◽  
Oleaginous Yeast ◽  
Fermentation Broth ◽  
Continuous Production ◽  
Oil Production ◽  
Biofuel Production ◽  
Oil Yield ◽  
Microbial Oil

Abstract Background Recent trends in bioprocessing have underlined the significance of lignocellulosic biomass conversions for biofuel production. These conversions demand at least 90% energy upgradation of cellulosic sugars to generate renewable drop-in biofuel precursors (Heff/C ~ 2). Chemical methods fail to achieve this without substantial loss of carbon; whereas, oleaginous biological systems propose a greener upgradation route by producing oil from sugars with 30% theoretical yields. However, these oleaginous systems cannot compete with the commercial volumes of vegetable oils in terms of overall oil yields and productivities. One of the significant challenges in the commercial exploitation of these microbial oils lies in the inefficient recovery of the produced oil. This issue has been addressed using highly selective oil capturing agents (OCA), which allow a concomitant microbial oil production and in situ oil recovery process. Results Adsorbent-based oil capturing agents were employed for simultaneous in situ oil recovery in the fermentative production broths. Yarrowia lipolytica, a model oleaginous yeast, was milked incessantly for oil production over 380 h in a media comprising of glucose as a sole carbon and nutrient source. This was achieved by continuous online capture of extracellular oil from the aqueous media and also the cell surface, by fluidizing the fermentation broth over an adsorbent bed of oil capturing agents (OCA). A consistent oil yield of 0.33 g per g of glucose consumed, corresponding to theoretical oil yield over glucose, was achieved using this approach. While the incorporation of the OCA increased the oil content up to 89% with complete substrate consumptions, it also caused an overall process integration. Conclusion The nondisruptive oil capture mediated by an OCA helped in accomplishing a trade-off between microbial oil production and its recovery. This strategy helped in realizing theoretically efficient sugar-to-oil bioconversions in a continuous production process. The process, therefore, endorses a sustainable production of molecular drop-in equivalents through oleaginous yeasts, representing as an absolute microbial oil factory.

scholarly journals Manipulation of surface charges of oil droplets and carbonate rocks to improve oil recovery

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Jian Hou ◽  
Ming Han ◽  
Jinxun Wang
Keyword(s):  
Zeta Potential ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Zwitterionic Surfactant ◽  
Surface Charges ◽  
Oil Droplets ◽  
Zeta Potentials ◽  
Potential Value ◽  
Oil Water ◽  
Incremental Oil Recovery

AbstractThis work investigates the effect of the surface charges of oil droplets and carbonate rocks in brine and in surfactant solutions on oil production. The influences of the cations in brine and the surfactant types on the zeta-potentials of both oil droplets and carbonate rock particles are studied. It is found that the addition of anionic and cationic surfactants in brine result in both negative or positive zeta-potentials of rock particles and oil droplets respectively, while the zwitterionic surfactant induces a positive charge on rock particles and a negative charge on oil droplets. Micromodels with a CaCO3 nanocrystal layer coated on the flow channels were used in the oil displacement tests. The results show that when the oil-water interfacial tension (IFT) was at 10−1 mN/m, the injection of an anionic surfactant (SDS-R1) solution achieved 21.0% incremental oil recovery, higher than the 12.6% increment by the injection of a zwitterionic surfactant (SB-A2) solution. When the IFT was lowered to 10−3 mM/m, the injection of anionic/non-ionic surfactant SMAN-l1 solution with higher absolute zeta potential value (ζoil + ζrock) of 34 mV has achieved higher incremental oil recovery (39.4%) than the application of an anionic/cationic surfactant SMAC-l1 solution with a lower absolute zeta-potential value of 22 mV (30.6%). This indicates that the same charge of rocks and oil droplets improves the transportation of charged oil/water emulsion in the porous media. This work reveals that the surface charge in surfactant flooding plays an important role in addition to the oil/water interfacial tension reduction and the rock wettability alteration.

Waterflooding in Carbonate Reservoirs: Does the Salinity Matter?

2014 ◽  
Vol 17 (03) ◽  
pp. 304-313 ◽  
Author(s):  
A.M.. M. Shehata ◽  
M.B.. B. Alotaibi ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Oil Recovery ◽  
Sudden Change ◽  
Oil Production ◽  
Deionized Water ◽  
Production Performance ◽  
Shallow Aquifer ◽  
Secondary Recovery ◽  
Tertiary Recovery ◽  
The Impact ◽  
Indiana Limestone

Summary Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable. In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195°F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na+, Ca2+, Mg2+, and SO42−) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment. The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca2+, Mg2+, and SO42− ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.

Oil, Water, Slag Three Phases Separation Technology of Heavy Aging Oil

2014 ◽  
Vol 936 ◽  
pp. 1553-1555
Author(s):  
Meng Zheng
Keyword(s):  
Water Content ◽  
Field Test ◽  
Oil Recovery ◽  
Recovery Rate ◽  
Storage Capacity ◽  
Quality Requirements ◽  
Separation Technology ◽  
Oil Water ◽  
Export Quality ◽  
Three Phases

The technology was used for handling heavy aging oil by demulsifier and three phases horizontal scrow centrifuge. Through laboratory and field test, it showed that the water content of the processed aging oil dropped from 50% to 5% below, purity oil recovery rate reached more than 95%, meeting export quality requirements. The technology improved the effective storage capacity of flow station, is of great significance to the safe and steady operation of flow station.

Characterization of Oil−Water Emulsion and Its Use in Enhanced Oil Recovery

2010 ◽  
Vol 49 (24) ◽  
pp. 12756-12761 ◽  
Author(s):  
Ajay Mandal ◽  
Abhijit Samanta ◽  
Achinta Bera ◽  
Keka Ojha
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Emulsion ◽  
Oil Water

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.

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