Can Indigenous Bacteria be Utilized for Increasing Oil Recovery from Trinidad Oil Reservoirs?

2014 ◽  
Author(s):  
N.. Rambaran ◽  
S.. Maharaj ◽  
R.. Hosein
Keyword(s):  
Oil Recovery ◽  
Low Cost ◽  
Oil Reservoirs ◽  
Bacillus Species ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Indigenous Bacteria ◽  
Colony Forming Units ◽  
Plate Counts ◽  
By Products

Abstract In Microbial Enhanced Oil Recovery (MEOR) oil mobility and oil recovery is increased by growing and reproducing microbes (bacteria) in oil reservoirs. The oil reservoir is either innoculated with a proprietry bacteria and then fed to grow or indigeneous microbes present are fed by the injection of a suitable nutrient identified from labotatory experiments. The metabolic by-products produced by these microorganisms causes a reduction in oil viscosity and interfacial tension and an increase in oil mobility. Although MEOR is not popular, the open literature has shown this to be a low cost mechanism that can be implemented with waterflood projects to increase the recovery of residual oil by another 1-5 %. In this study an oil sample from an oil reservoir in the South of Trinidad was selected and the indigenous bacteria present was identified to be mainly of the Bacillus species. A quantification of this indigenous bacteria by plate counts showed that the aerobic colony forming units (CFU) was about 1.5×106 CFU/ml whereas the observed anaerobic plate counts was about 9.0×102 CFU/ml. Growth of the indigenous bacteria was stimulated by innoculating the oil sample with five different nutrient formulations for a period of three weeks so as to select the most suitable nutrient. However, the growth in bacteria was too numerous to count even after one week. Experimental measurements showed that the sample innoculated with the nutrient broth formulation had the greatest change in oil properties. The reduction in oil viscosity was 49 % and the reduction in interficial tension was 17 %. The results from this study can be included in waterfloood simulation studies for suitable oil reservoirs in Trinidad to determine the added increase in oil mobility and oil recovery from a combination of waterflood and MEOR.

Prediction of Recovery in Unstable Miscible Flooding

1972 ◽  
Vol 12 (02) ◽  
pp. 143-155 ◽  
Author(s):  
E.L. Claridge
Keyword(s):  
Economic Evaluation ◽  
Crude Oil ◽  
Oil Recovery ◽  
Pore Space ◽  
Vertical Direction ◽  
Oil Reservoirs ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Recovery Processes ◽  
First Choice

Abstract A new correlation bas been developed for estimating oil recovery in unstable miscible five-spot pattern floods. It combines existing methods of predicting areal coverage and linear displacement efficiency and was used to calculate oil recovery for a series of assumed slug sizes in a live-spot CO2 slug-waterflood pilot test. The economic optimum slug size varies with CO2 cost; at anticipated CO2 costs the pilot would generate an attractive profit if performance is as predicted Introduction Selection of good field prospects for application of oil recovery processes other than waterflooding is often difficult. The principal reason is that other proposed displacing agents are far more costly proposed displacing agents are far more costly than water and usually sweep a lesser fraction of the volume of an oil reservoir (while displacing oil more efficiently from this fraction). Such agents must be used in limited amounts as compared with water; and this amount must achieve an appreciable additional oil recovery above waterflooding recovery. For these reasons, there is in general much less economic margin for engineering error in processes other than waterflooding. The general characteristics of the various types of supplemental recovery processes are well known, and adequate choices can be made of processes to be considered in more detail with respect to a given field. Comparative estimates must then be made of process performance and costs in order to narrow the choice. A much more detailed, definitive process-and-economic evaluation is eventually process-and-economic evaluation is eventually required of the chosen process before an executive decision can be made to commit large amounts of money to such projects. It is in the area between first choice and final engineering evaluation that this work applies. A areal cusping and vertical coning into producing wells. These effects can be seated by existing "desk-drawer" correlation which can confirm or deny the engineer's surmise that he has an appropriate match of recovery process and oil reservoir characteristics is of considerable value in determining when to undertake the costly and often manpower-consuming task of a definitive process-and-economic evaluation. process-and-economic evaluation. An examination of the nature of the developed crude oil resources in the U.S. indicates that the majority of the crude oil being produced is above 35 degrees API gravity and exists in reservoirs deeper than 4,000 ft. The combination of hydrostatic pressure on these oil reservoirs, the natural gas usually present in the crude oil in proportion to this pressure, the reservoir temperatures typically found, and the distribution of molecular sizes and types in the crude oil corresponding to the API gravity results in the fact that, in the majority of cases, the in-place crude oil viscosity was originally no more than twice that of water. A large proportion of these oil reservoirs have undergone pressure decline, gas evolution and consequent increase in crude oil viscosity. However, an appreciable proportion are still at such a pressure and proportion are still at such a pressure and temperature that miscibility can be readily attained with miscible drive agents such as propane or carbon dioxide, and the viscosity of the crude oil is such that the mobility of these miscible drive agents is no more than 50 time s that of the crude oil. Under these circumstances, a possible candidate situation for the miscible-drive type of process may exist. process may exist. Supposing that such a situation is under consideration, the next question is: what specific miscible drive process, and how should it be designed to operate? In some cases, the answer is clear: when the reservoir has a high degree of vertical communication (high permeability and continuity of the permeable, oil-bearing pore space in the vertical direction), then a gravity-stabilized miscible flood is the preferred mode of operation; and the particular drive agent or agents can be chosen on the basis of miscibility requirements, availability and cost. SPEJ P. 143

Experimental Analysis of the Effects of Varying Temperature and Viscosities on Foamy Oil Production

2021 ◽  
Author(s):  
Jasmine Shivani Medina ◽  
Iomi Dhanielle Medina ◽  
Gao Zhang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Elevated Temperatures ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Gas Recovery ◽  
Foamy Oil ◽  
Heavy Oil Reservoirs ◽  
Pressure Depletion

Abstract The phenomenon of higher than expected production rates and recovery factors in heavy oil reservoirs captured the term "foamy oil," by researchers. This is mainly due to the bubble filled chocolate mousse appearance found at wellheads where this phenomenon occurs. Foamy oil flow is barely understood up to this day. Understanding why this unusual occurrence exists can aid in the transfer of principles to low recovery heavy oil reservoirs globally. This study focused mainly on how varying the viscosity and temperature via pressure depletion lab tests affected the performance of foamy oil production. Six different lab-scaled experiments were conducted, four with varying temperatures and two with varying viscosities. All experiments were conducted using lab-scaled sand pack pressure depletion tests with the same initial gas oil ratio (GOR). The first series of experiments with varying temperatures showed that the oil recovery was inversely proportional to elevated temperatures, however there was a directly proportional relationship between gas recovery and elevation in temperature. A unique observation was also made, during late-stage production, foamy oil recovery reappeared with temperatures in the 45-55°C range. With respect to the viscosities, a non-linear relationship existed, however there was an optimal region in which the live-oil viscosity and foamy oil production seem to be harmonious.

An Investigation Into Propagation Behavior of the Steam Chamber During Expanding-Solvent SAGP (ES-SAGP)

SPE Journal ◽  
2019 ◽  
Vol 24 (02) ◽  
pp. 413-430
Author(s):  
Zhanxi Pang ◽  
Lei Wang ◽  
Zhengbin Wu ◽  
Xue Wang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Physical Simulation ◽  
Heat Losses ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Experimental Conditions ◽  
Steam Chamber ◽  
Heavy Oil Reservoirs

Summary Steam-assisted gravity drainage (SAGD) and steam and gas push (SAGP) are used commercially to recover bitumen from oil sands, but for thin heavy-oil reservoirs, the recovery is lower because of larger heat losses through caprock and poorer oil mobility under reservoir conditions. A new enhanced-oil-recovery (EOR) method, expanding-solvent SAGP (ES-SAGP), is introduced to develop thin heavy-oil reservoirs. In ES-SAGP, noncondensate gas and vaporizable solvent are injected with steam into the steam chamber during SAGD. We used a 3D physical simulation scale to research the effectiveness of ES-SAGP and to analyze the propagation mechanisms of the steam chamber during ES-SAGP. Under the same experimental conditions, we conducted a contrast analysis between SAGP and ES-SAGP to study the expanding characteristics of the steam chamber, the sweep efficiency of the steam chamber, and the ultimate oil recovery. The experimental results show that the steam chamber gradually becomes an ellipse shape during SAGP. However, during ES-SAGP, noncondensate gas and a vaporizable solvent gather at the reservoir top to decrease heat losses, and oil viscosity near the condensate layer of the steam chamber is largely decreased by hot steam and by solvent, making the boundary of the steam chamber vertical and gradually a similar, rectangular shape. As in SAGD, during ES-SAGP, the expansion mechanism of the steam chamber can be divided into three stages: the ascent stage, the horizontal-expansion stage, and the descent stage. In the ascent stage, the time needed is shorter during ES-SAGP than during SAGP. However, the other two stages take more time during nitrogen, solvent, and steam injection to enlarge the cross-sectional area of the bottom of the steam chamber. For the conditions in our experiments, when the instantaneous oil/steam ratio is lower than 0.1, the corresponding oil recovery is 51.11%, which is 7.04% higher than in SAGP. Therefore, during ES-SAGP, not only is the volume of the steam chamber sharply enlarged, but the sweep efficiency and the ultimate oil recovery are also remarkably improved.

scholarly journals Experimental Investigation of Oil Recovery from Tight Sandstone Oil Reservoirs by Pressure Depletion

Energies ◽  
2018 ◽  
Vol 11 (10) ◽  
pp. 2667 ◽  
Author(s):  
Wenxiang Chen ◽  
Zubo Zhang ◽  
Qingjie Liu ◽  
Xu Chen ◽  
Prince Opoku Appau ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Reservoirs ◽  
Oil Reservoir ◽  
Reservoir Pressure ◽  
Dissolved Gas ◽  
Tight Sandstone ◽  
Bubble Point ◽  
Bubble Point Pressure ◽  
Pressure Depletion ◽  
Point Pressure

Oil production by natural energy of the reservoir is usually the first choice for oil reservoir development. Conversely, to effectively develop tight oil reservoir is challenging due to its ultra-low formation permeability. A novel platform for experimental investigation of oil recovery from tight sandstone oil reservoirs by pressure depletion has been proposed in this paper. A series of experiments were conducted to evaluate the effects of pressure depletion degree, pressure depletion rate, reservoir temperature, overburden pressure, formation pressure coefficient and crude oil properties on oil recovery by reservoir pressure depletion. In addition, the characteristics of pressure propagation during the reservoir depletion process were monitored and studied. The experimental results showed that oil recovery factor positively correlated with pressure depletion degree when reservoir pressure was above the bubble point pressure. Moreover, equal pressure depletion degree led to the same oil recovery factor regardless of different pressure depletion rate. However, it was noticed that faster pressure drop resulted in a higher oil recovery rate. For oil reservoir without dissolved gas (dead oil), oil recovery was 2–3% due to the limited reservoir natural energy. In contrast, depletion from live oil reservoir resulted in an increased recovery rate ranging from 11% to 18% due to the presence of dissolved gas. This is attributed to the fact that when reservoir pressure drops below the bubble point pressure, the dissolved gas expands and pushes the oil out of the rock pore spaces which significantly improves the oil recovery. From the pressure propagation curve, the reason for improved oil recovery is that when the reservoir pressure is lower than the bubble point pressure, the dissolved gas constantly separates and provides additional pressure gradient to displace oil. The present study will help engineers to have a better understanding of the drive mechanisms and influencing factors that affect development of tight oil reservoirs, especially for predicting oil recovery by reservoir pressure depletion.

scholarly journals The Research and Application of Microbial Degradation Technology on Heavy Oil Reservoir in Huabei Oilfield

2018 ◽  
Vol 38 ◽  
pp. 01054
Author(s):  
Guan Wang ◽  
Rui Wang ◽  
Yaxiu Fu ◽  
Lisha Duan ◽  
Xizhi Yuan ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
High Surface ◽  
Effective Rate ◽  
Water Flooding ◽  
Oil Reservoir ◽  
Displacement Efficiency ◽  
Oil Viscosity ◽  
Reservoir Conditions ◽  
Heavy Oil Reservoir

Mengulin sandstone reservoir in Huabei oilfield is low- temperature heavy oil reservoir. Recently, it is at later stage of waterflooding development. The producing degree of water flooding is poor, and it is difficult to keep yield stable. To improve oilfield development effect, according to the characteristics of reservoir geology, microbial enhanced oil recovery to improve oil displacement efficiency is researched. 2 microbial strains suitable for the reservoir conditions were screened indoor. The growth characteristics of strains, compatibility and function mechanism with crude oil were studied. Results show that the screened strains have very strong ability to utilize petroleum hydrocarbon to grow and metabolize, can achieve the purpose of reducing oil viscosity, and can also produce biological molecules with high surface activity to reduce the oil-water interfacial tension. 9 oil wells had been chosen to carry on the pilot test of microbial stimulation, of which 7 wells became effective with better experiment results. The measures effective rate is 77.8%, the increased oil is 1,093.5 tons and the valid is up to 190 days.

Unsteady-State Distributions of Fluid Compositions in Two-Phase Oil Reservoirs Undergoing Gas Injection

1967 ◽  
Vol 7 (01) ◽  
pp. 61-74 ◽  
Author(s):  
Robert C. McFarlane ◽  
T.D. Mueller ◽  
F.G. Miller
Keyword(s):  
Oil Recovery ◽  
High Speed ◽  
Gas Injection ◽  
Gas Storage ◽  
Oil Reservoirs ◽  
Oil Reservoir ◽  
Two Phase ◽  
Secondary Recovery ◽  
Compositional Effects ◽  
Gas Cycling

Abstract During the process of gas storage in pressure-depleted oil reservoirs, it has been observed that in some instances additional liquid oil is recovered and that the composition of the storage gas is materially altered. A mathematical study was made of the dynamic behavior of such a depleted oil reservoir undergoing gas injection. The important variable considered in this study, not included in previously published work, was that of compositional effects on the phase behavior of two-phase flow. Pressure, saturation and component composition profiles were developed for a linear, horizontal and homogeneous porous medium containing oil and gas but undergoing dry gas injection. Special new techniques were developed to overcome the problems of numerical smoothing which arise in the solution of the equations representing such systems. The method of solution includes the development of partial differential equations describing the behavior of the system, representing these equations by finite difference approximations, making certain simplifying assumptions and, finally, applying methods of numerical analysis with the aid of a high-speed digital computer. In an example calculation, results using the mathematical model are compared with field observations made on a gas storage project in Clay County, Tex. This field project involved a depleted oil reservoir used' for gas storage and gas cycling purposes. As a result of these processes, the reservoir yielded substantial amounts of secondary oil, both in the form of stock tank oil and as vaporized products in the produced gas. The methods derived in this study may be applied to a variety of oil reservoir problems which are dependent on compositional effects. INTRODUCTION In recent years the number of oil reservoirs being used for gas storage purposes has increased greatly, and there has been at least one published account of additional oil recovery resulting from gas cycling a depleted oil reservoir after repressuring with dry gas for storage purposes. Additional oil recovery from oil reservoirs resulting from gas storage operations could become an important secondary recovery process. This is especially true since the use of natural gas in large metropolitan areas continues to increase and more gas storage volume near these areas is needed. These facts provided the motivation for the work reported here. This paper reports on a study of the inter-relations of composition, saturation and pressure changes which occur when hydrocarbon gas is injected into an oil reservoir system. From an understanding of the process, prediction methods may be developed for use in forecasting the secondary recovery products from gas storage operations in oil reservoirs and, consequently, .the economics of such projects can be developed.

Research on CO2 EOR Mechanism and Application in Shengli Oilfield

2011 ◽  
Vol 474-476 ◽  
pp. 744-747
Author(s):  
Guang Zhong Lv ◽  
Jian Zhang ◽  
Feng Wang ◽  
Guang Hong Yan ◽  
Xin Jun Zhang
Keyword(s):  
Low Cost ◽  
Oil Field ◽  
Core Model ◽  
Test Block ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Shengli Oilfield ◽  
Expansion Mechanism

As one kind of oil expellant in improving the recovery ration of oil reservoir (EOR), CO2 flooding has merits such as extensive adaptability, low cost, high recoverability, and it will become one main way of EOR in future. In this paper, the EOR mechanism of CO2 flooding has been studied correspond to the geologic conditions in Shengli oil field, which includes three parts: mechanism of expansion, mechanism of reduce oil viscosity and displacement experiment of long core model. Moreover, the detailed process of the test block description of CO2 flooding in Shengli oil field has been set forth. Through the application in Shengli oil field proves that the EOR mechanism of CO2 flooding is right and suits for geologic conditions in Shengli oil field.

Methane Pressure-Cycling Process With Horizontal Wells for Thin Heavy-Oil Reservoirs

2006 ◽  
Vol 9 (02) ◽  
pp. 154-164 ◽  
Author(s):  
Mingzhe Dong ◽  
S.-S. Sam Huang ◽  
Keith Hutchence
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Flue Gas ◽  
Oil Reservoirs ◽  
Heavy Oil Recovery ◽  
Oil Viscosity ◽  
Pressure Cycling ◽  
Oil Resources ◽  
Heavy Oil Reservoirs ◽  
Secondary Methods

Summary The methane pressure-cycling (MPC) process is an enhanced-oil-recovery (EOR) scheme intended for application in some heavy-oil reservoirs after termination of either primary or waterflood production. The essence of the process is the restoration of the solution-gas-drive mechanism. The restoration is accomplished by reinjecting an appropriate amount of solution gas (mainly methane) and then repressuring the gas back into solution by injecting water until approximate original reservoir pressure is reached. This, aside from the replacement of produced oil by water, recreates the primary-production conditions. This novel recovery technique is being developed to target the considerable portion of heavy-oil resources located in thin reservoirs. Primary and secondary methods have managed to recover at best 10% of the initial oil in place (IOIP). Heat losses to overburden and underburden or bottomwater zones make thermal methods unsuitable for thin reservoirs. Sandpack-flood tests in 30.5-cm (length) × 5.0-cm (diameter) sandpacks were carried out for oils with a range of dead-oil viscosities from 1700 to 5400 mPa.s. The results showed that the pressure-cycling process could create a favorable condition for recharged gas to contact the remaining oil in reservoirs. This restores the situation whereby substantial amounts of gas are in solution for further "primary" production. The effects on the efficiency of the MPC process of cycle termination strategy, oil viscosity, and mobile-water saturation were investigated. Simulations were conducted to investigate the MPC process in three heavy-oil reservoirs in Saskatchewan, Canada. The effects on the process of infill wells, oil viscosity, gas-injection rate, and the presence of wormholes in reservoirs were studied. Introduction Heavy oil in thick-pay reservoirs (i.e., >10 m) is commonly produced with thermal-recovery methods. These methods (steam injection and its variants) are generally not suitable for thin reservoirs because of heat losses to overburden and underburden or bottomwater zones (Fairfield and White 1982; Dyer et al. 1994). The world's large untapped oil resource remaining after recovery by conventional technology offers potential for exploitation by a suitably developed tertiary-recovery technique. For example, Saskatchewan accounts for 62% of Canada's total heavy-oil resources (Bowers and Drummond 1997), including 1.7 billion m3 of proved reserves and 3.7 billion m3 of probable reserves (Saskatchewan Energy and Mines 1998). Of the province's proven initial heavy oil in place, 97% is contained in reservoirs where the pay zone is less than 10 m, and 55% in reservoirs with a pay zone less than 5 m thick (Huang et al. 1987; Srivastava et al. 1993). Primary and secondary methods combined recover, on average, only about 7% of the proven IOIP (Saskatchewan Energy and Mines 1998). The incentive is strong for the development of appropriate EOR techniques that will maximize the recovery potential of and profitability from these thin heavy-oil reservoirs. Extensive literature is available on CO2, flue gas, and produced-gas injection for heavy-oil recovery, including slug displacement, water alternating gas (WAG), and cyclic (huff ‘n’ puff) processes (Huang et al. 1987; Srivastava et al. 1993, 1994, 1999; Srivastava and Huang 1997; Ma and Youngren 1994; Issever et al. 1993; Olenick et al. 1992). A comparative study of the oil-recovery behavior for a 14.1°API heavy oil with different injection gases (CO2, flue gas, and produced gas) showed that CO2 was the best-suited gas for EOR of heavy oils (Srivastava et al. 1999). Cyclic CO2 injection for heavy-oil recovery was tested in the field, and field case histories indicated that oil production was enhanced (Olenick et al. 1992). However, natural CO2 sources are not available to most oil reservoirs. The cost of CO2 capture from flue gas and other sources may range from U.S. $25 to $70/ton (Padamsey and Railton 1993). Produced gas is available in large quantities at a much lower cost. With this consideration, produced gas can be an economically effective agent for heavy-oil recovery by the cyclic-injection process.

Thermally Active Polymer To Improve Sweep Efficiency of Waterfloods: Simulation and Pilot Design Approaches

2012 ◽  
Vol 15 (01) ◽  
pp. 86-97 ◽  
Author(s):  
R.. Garmeh ◽  
M.. Izadi ◽  
M.. Salehi ◽  
J.L.. L. Romero ◽  
C.P.. P. Thomas ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Pilot Project ◽  
Oil Reservoirs ◽  
Reservoir Rock ◽  
Sensitivity Analyses ◽  
Chemical Components ◽  
Chemical Adsorption ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Thief Zone

Summary A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer (TAP), which is an expandable submicron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods. This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot-project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature-triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed. Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief-zone permeability and diverts flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depend on the thief-zone temperature, vertical-to the horizontal-permeability ratio (Kv/Kh), thief-zone vertical location, injection concentration and slug size, oil viscosity, and chemical adsorption and its reversibility, among other factors. For high-flow-capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Reservoirs with low Kv/Kh (< 0.1) and high permeability contrast generally shows faster incremental recoveries than reservoirs with high Kv/Kh and strong water segregation. The presented workflow is currently used to perform in-depth conformance treatment designs in onshore and offshore fields and can be used as a reference tool to evaluate benefits of the TAP in waterflooded oil reservoirs.

scholarly journals Experimental study of microbial enhanced oil recovery in oil-wet fractured porous media

2020 ◽  
Vol 75 ◽  
pp. 73
Author(s):  
Amin Abolhasanzadeh ◽  
Ali Reza Khaz’ali ◽  
Rohallah Hashemi ◽  
Mohammadhadi Jazini
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Low Cost ◽  
Fractured Reservoirs ◽  
Gas Production ◽  
Wettability Alteration ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
The Matrix ◽  
Microbial Flooding

Without Enhanced Oil Recovery (EOR) operations, the final recovery factor of most hydrocarbon reservoirs would be limited. However, EOR can be an expensive task, especially for methods involving gas injection. On the other hand, aqueous injection in fractured reservoirs with small oil-wet or mixed-wet matrices will not be beneficial if the rock wettability is not changed effectively. In the current research, an unpracticed fabrication method was implemented to build natively oil-wet, fractured micromodels. Then, the efficiency of microbial flooding in the micromodels, as a low-cost EOR method, is investigated using a new-found bacteria, Bacillus persicus. Bacillus persicus improves the sweep efficiency via reduction of water/oil IFT and oil viscosity, in-situ gas production, and wettability alteration mechanisms. In our experiments, the microbial flooding technique extracted 65% of matrix oil, while no oil was produced from the matrix system by water or surfactant flooding.

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