Oil Bank Research Articles

Oil Price Shocks and Bank Risk around the World

This paper provides global evidence that oil price shocks have significant impacts on bank risk. Specifically, all three oil shocks, including oil supply shocks, aggregate demand shocks, and oil specific demand shocks, have positive impacts on bank risk. In particular, oil specific demand shocks have different impacts on bank risk in oil-importing versus oil-exporting countries and in normal times versus the financial crisis period. Moreover, we find that interest rate spread could significantly explain the impacts of oil shocks on bank risk for oil-exporting countries during normal times. Our main results remain valid in various robustness tests.This study provides important practical implications for policy makers, banks, and investors around the world.

Laboratory comparison of tertiary N2, CH4, and CO2 injection into an Inland oil field sample

Few laboratory studies compared tertiary gas injection using N2, CH4, and CO2. However, these studies only focussed on oil recovery without examining CO2 storage. This study experimentally compares the oil recovery performance of tertiary N2, CH4, and CO2 injection into a composite Hutton Sandstone core taken from the Inland oil field, Australia. CO2 storage during tertiary CO2 injection is recorded. The core receives an initial injection, which is oil; then a secondary injection, which is water; and finally a tertiary injection, which is N2, CH4, or CO2. Pressure difference across the core and fluid production are recorded. Compositional analysis is performed on the produced oil samples. To estimate oil saturation distribution in the core, numerical simulations are run to simulate the injection experiment.Tertiary oil recovery for CO2 injection is found to be 23.1% of the original oil in-place, which far exceeds the 7.3% for CH4 injection and 5.3% for N2 injection. Ultimate oil recovery was 76.5% for tertiary CO2 injection, 59.6% for tertiary CH4 injection, and 58.3% for tertiary N2 injection. We observed that tertiary oil recovery for each injected gas begins with the oil bank it has generated being produced at a reasonably constant rate after which, the production rate declines reflecting the declining oil concentration in the oil bank. For tertiary CO2 injection, mass transfer between oil and CO2 is observed, which is found to lead to more production of the lighter oil after the oil bank production stage. In addition, tertiary CO2 injection is found to store 0.57 pore volume of the injected CO2 in the core.

Phenomenon of triple jump in propagation of microbial waves through porous media: Example of oil recovery

We analyze the problem of injection of water with micro-organisms into an underground porous medium containing another fluid (oil or gas). The microbes produce a metabolite (a surfactant) that changes capillary and wetting properties between the fluids, which increases the oil mobility. We analyze the Riemann problem for balance equations, which has been reduced to a hyperbolic system of fourth degree. The fractional flow function (F) is assumed to be discontinuous with respect to the surfactant concentration, which provides us the opportunity to develop a qualitative theory of the process and even to obtain the analytical solution. We have determined explicitly the characteristic speeds of continuous waves, several contact jumps, and shock waves, along with a non-classical element, such as a triple jump, the initial state of which is a thorn of saturation. We have shown that a triple jump and a thorn are not numerical artifacts, but true physical objects that satisfy the mass balance and the entropy conditions. Physically, a triple jump means the fast variation of wetting, which leads to the formation of an oil bank and a water wall in front of it. We have revealed a complete qualitative scenario for the propagation of saturation and concentrations, which contains several steps. This information makes it possible to control the correctness of numerical simulation of the process. The subsequent numerical analysis was based on four methods: Godunov's, MacCormack's, upwind and an implicit scheme with small diffusion. Their free parameters were calibrated to reproduce all the stages of the scenario identified analytically. We analyze the ability of various numerical schemes to capture triple jumps and thorns, comparing with the analytical solution.

The Role of Immiscible Fingering on the Mechanism of Secondary and Tertiary Polymer Flooding of Viscous Oil

Immiscible viscous fingering in porous media occurs when a low viscosity fluid displaces a significantly more viscous, immiscible resident fluid; for example, the displacement of a higher viscosity oil with water (where μo > > μw). Classically, this is a significant issue during oil recovery processes, where water is injected into the reservoir to provide pressure support and to drive the oil production. In moderate/heavy oil, this leads to the formation of strong water fingers, bypassed oil and high/early water production. Polymer flooding, where the injected water is viscosified through addition of high molecular weight polymers, has often been applied to reduce the viscosity contrast between the two immiscible fluids. In recent years, there has been significant development in the understanding of both the mechanism by which polymer flooding improves viscous oil recovery, as well as in the methodologies available to directly simulate such processes. One key advance in modelling the correct mechanism of polymer oil recovery in viscous oils has been the development of a method to accurately model the “simple” two-phase immiscible fingering (Sorbie in Transp Porous Media 135:331–359, 2020). This was achieved by first choosing the correct fractional flow and then deriving the maximum mobility relative permeability functions from this. It has been proposed that central to the polymer oil recovery is a fingering/viscous crossflow mechanism, and a summary of this is given in this paper. This work seeks to validate the proposed immiscible fingering/viscous crossflow mechanism experimentally for a moderately viscous oil (μo = 84 mPa.s at 31 °C; μw = 0.81 mPa.s; thus, (μo/μw) ~ 104) by performing a series of carefully monitored core floods. The results from these experiments are simulated directly to establish the potential of our modified simulation approach to capture the process (Sorbie, et al., 2020). Both secondary and tertiary polymer flooding experiments are presented and compared with the waterflood baselines, which have been established for each core system. The oil production, water cut and differential pressure are then matched directly using a commercial numerical reservoir simulator, but using our new “fractional flow” derived relative permeabilities. The use of polymer flooding, even when applied at a high water cut (80% after 0.5 PV of water injection), showed a significant impact on recovery; bringing the recovery significantly forward in time for both tertiary and secondary polymer injection modes—a further 13–16% OOIP. Each flood was then directly matched in the simulator with excellent agreement in all experimental cases. The simulations allowed a quantitative visualisation of the immiscible finger propagation from both water injection and the banking of connate water during polymer flooding. Evidence of a strong oil bank forming in front of the tertiary polymer slug was also observed, in line with the proposed viscous crossflow mechanism. This work provides validation of both polymer flooding’s viscous crossflow mechanism and the direct simulation methodology proposed by Sorbie et al. (Transp Porous Media 135:331–359, 2020). The experimental results show the significant potential for both secondary and tertiary polymer flooding in moderate/heavy oil reservoirs.

Geological Model of the Khabour Reservoir for Studying the Gas Condensate Blockage Effect on Gas Production, Akkas Gas Field, Western Iraq

The Khabour reservoir, Ordovician, Lower Paleozoic, Akkas gas field which is considered one of the main sandstone reservoirs in the west of Iraq. Researchers face difficulties in recognizing sandstone reservoirs since they are virtually always tight and heterogeneous. This paper is associated with the geological modeling of a gas-bearing reservoir that containing condensate appears while production when bottom hole pressure declines below the dew point. By defining the lithology and evaluating the petrophysical parameters of this complicated reservoir, a geological model for the reservoir is being built by using CMG BUILDER software (GEM tool) to create a static model. The petrophysical properties of a reservoir were computed using the notion of hydraulic units, and there are a number of basic steps to building a geological model, beginning with the creation of a single well model and then moving on to the distribution of properties. Depending on the variance in petrophysical parameters, the reservoirs were separated into seven zones. The Ordovician Formation (Khabour Formation) is penetrated by well Akk-1, which is included in the single well geological model to focus on studying the impact of gas condensate on gas production. The prediction of gas condensate wells production will strongly depend on oil banking evaluation and modeling. For this reason, well Akk-1 was chosen to build the model. Upper and lower sandstone units characterized as the most important due to containing of gas. The cost and risk to develop these reservoirs under severe conditions of pressure and temperature highlight the need to be able to confidently predict the recovery of gas and liquid drop-outs from Khabour reservoirs so, it is so necessary to predict the cost of this step in another paper

Heavy Oil Recovery by Alkaline-Cosolvent-Polymer Flood: A Multiscale Research Using Micromodels and Computed Tomography Imaging

Summary For reservoirs containing oil with a high total acid number, the alkali-cosolvent-polymer (ACP) flood can promote the formation of microemulsion rather than viscous macroemulsion and achieve good mobility control. The enhanced oil recovery (EOR) performance of ACP flood has been studied at core and reservoir scale in detail; however, the effect of ACP flood on residual oil still lacks enough research. In this paper, a micromodel with a single channel is used to clarify the dynamic effects of alkali-cosolvent (AC) and ACP solutions on the residual oil after waterflood. Based on this, medical computed tomography (Medical-CT) scan and microcomputed tomography (Micro-CT) scan are used in combination to visualize microscale flow and reveal the mechanisms of residual oil reduction during ACP flood. The heterogeneous core plugs containing two layers of different permeabilities are used for coreflood experiments to clarify the EOR performance of ACP flood in heterogeneous reservoirs. The oil saturation is monitored by Medical-CT. Then, two core samples are drilled in each core plug that is used in the coreflood experiment. The decrease of residual oil saturation caused by ACP flood is further quantified by Micro-CT imaging. Results show that ACP flood is 14.5% oil recovery higher than AC flood (68.9%) in relative high permeability layers (HPLs) and 17.9% higher than AC flood (26.3%) in relative low permeability layers (LPLs). Compared with AC flood, ACP flood shows a more uniform displacement front, which implies that the injected polymer effectively weakened the viscosity fingering. This is similar to the experimental results demonstrated visually in the micromodel experiments. ACP solution first generates an oil bank by the mobility ratio improvement to mobilize residual oil and then dissolve and emulsify residual oil under ultralow interfacial tension (IFT) conditions. Moreover, a method that can calculate the ratio of oil/water distribution in each pore is developed to establish the relationship between the residual oil saturation of each pore and its pore size, and concluded that they follow the power-law correlation.

Cyclic In-Situ Combustion Process for Improved Heavy Oil Recovery after Cyclic Steam Stimulation

Summary Cyclic in-situ combustion (ISC) is a novel process with great potential for thermal enhanced oil recovery (EOR). In this study, a 3D physical simulation experiment of cyclic ISC after cyclic steam stimulation (CSS) was carried out for the first time. The mass loss during heavy oil oxidation was studied by thermogravimetry (TG) and the preheating temperature of sandpack was determined by differential scanning calorimeter (DSC). The oxidation process of heavy oil in a porous medium was investigated by a heavy oil static oxidation experiment. The development characteristics and EOR mechanism of cyclic ISC after CSS were studied through 3D physical simulation experiments and the characteristics of the coking zone was studied by scanning electron microscope (SEM) and computed tomography (CT). The results of the thermal analysis indicate that three different regions were observed with increasing temperature: low-temperature oxidation zone (LTO), fuel deposition zone (FD), and high-temperature oxidation zone (HTO). When the temperature reaches 480°C, the mixed oil sand has the most exothermic effect and the high-temperature oxidation reaction is the most vigorous. The results of the 3D physical simulation show that steam channeling and steam overlay in CSS reduced the swept volume of steam and heat usage rate. During the cyclic ISC, the oil bank can overcome the heterogeneity of the oil reservoir caused by steam channeling and steam overlay, which makes the combustion front move forward smoothly. Cyclic ISC can greatly increase the temperature of the zone near the well, and upgrade the crude oil through cracking to reduce the viscosity of heavy oil. The foaming oil formed by the dissolution of flue gas improves the fluidity of the crude oil. The oil recovery of CSS is 19.3%, and the oil recovery of cyclic ISC increased by 13.2%. SEM and CT show that flake black solid coke was attached to the surface of the sand at the coking zone. The coking zone is a porous medium structure with a porosity of 35.14%, which has little effect on the oil recovery in the process of cyclic ISC.

Pore network-scale visualization of the effect of brine composition on sweep efficiency and speed of oil recovery from carbonates using a photolithography-based calcite microfluidic model

A novel photolithography-based technique was developed to fabricate a quasi-2D heterogeneous calcite micromodel of representative elementary volume size. The effect of brine-chemistry on the mobilization of capillarity and heterogeneity trapped oil after high salinity water injection was evaluated by using diluted seawater, and seawater modified with calcium, sulphate, and silica nanoparticles. Preliminary brine screening was performed based on modified contact angle experiments under dynamic salinity alteration. The main findings are that the chemical composition of brine impacts both the ultimate oil recovery and its speed. The highest and fastest oil recovery was obtained with diluted seawater and seawater augmented with nanoparticles. We also found that the ex-situ contact angle results, indicative of wettability alteration, can be predictive of each brine performance at the pore network-scale. A slow recovery process, from 7 days up to 12 days, without any oil banking, was observed with all the brines. Due to the time-dependent nature of the wettability alteration process, mere injection of brines, even several pore-volumes and the viscous force exerted by flooding, were not sufficient to result in any additional oil production. Oil production was obtained only during the shut-in period via enhanced spontaneous imbibition of brine into the pores and throats. This highlights that a sufficient soaking time (at least for laboratory scale experiments) would be necessary to assess suitability of brines and determine accurately the incremental oil recovery by low salinity waterflooding (LSWF).

A critical analysis on the effects of xanthan gum properties and its derivatives in enhanced oil recovery

Polymer flooding or mobility control techniques that focus on maintaining favorable mobility ratios can be used to improve volumetric sweep efficiency. The development of specialized polymer solutions optimizes the mobility ratio between the injected polymer solution and the oil or water bank being displaced in advance of the polymer. Because of its solid structure, lack of effect of salt on viscosity (unlike partially hydrolyzed polyacrylamide (HPAM), which has a salinity influence on viscosity), and lack of effect of high temperatures, xanthan gum, also known as polysaccharide biopolymer, is the most frequently utilized. This research investigates many properties of xanthan gum, as well as its effectiveness with other polymers and the modifications made to improve its performance.

Leaky waveguides in hydrocarbon reservoirs and their implications for oil banks detection

The presence of naturally occurring subsurface waveguides for electromagnetic (EM) waves has been previously documented. In particular, the mining industry recognized that a coal seam bounded by layers of conductive rock acts as a leaky waveguide. Consequently, the attenuation constant and phase shift of EM signals propagating through the coal layer are modulated by the thickness of the coal and the EM properties of the three layers forming the leaky waveguide. The radio imaging method was developed based on this discovery to characterize coal deposits. Recent studies have determined that guided waves can provide useful information about the subsurface. Structures with similar dimensions and EM properties are found in oil fields in the form of layers of evaporite (e.g., anhydrite) bounded by hydrocarbon reservoirs. To the best of our knowledge, the feasibility of exploiting such structures to characterize the interwell region has not been investigated extensively. We have conducted a theoretical analysis and 3D numerical simulations in the time and frequency domains to demonstrate that layered structures in oil fields can act as leaky waveguides and efficiently guide EM waves. Our results suggest that such structures substantially enhance the propagation of megahertz EM signals. Among multiple parameters evaluated, the conductivity of the layers has the most significant effect on signal attenuation, and thus its range of propagation. We estimated that EM signals of approximately 10 MHz can propagate several hundreds of meters through a layer of anhydrite in the presence of conductive bounding reservoirs. The received signals are not only affected by the properties of the anhydrite layer, but also by the properties of the bounding reservoirs, conferring sensitivity to changes in reservoir saturation. We conclude that this approach could be further developed to infer fluid saturation and especially to identify the presence of oil banks in water-flooded hydrocarbon reservoirs.

The Study of Flow Behavior and Performance of Polymer Injection in Homogenous Porous Media Using Etched Micromodel

The implementation of polymer injection on a field scale needs a preliminary laboratory test to analyze the performance and flow behavior of polymer injection in a porous media. Compared to coreflooding method, micromodel provides the visualization of oil displacement mechanism and facilitating a more detailed process description. Understanding the effect of polymer concentration on the incremental of oil recovery factor and its displacement mechanism are essential to know the polymer injection performance with the intention of avoiding failures in the implementation of polymer injection at field scale. We used dry etching technique for the fabrication of acrylic micromodel with homogenous characteristic. In this work, pre-flush (waterflooding) is performed first before doing the polymer injection to determine the incremental oil recovery factor and analyze the effect of polymer concentration on oil recovery factor enhancement in homogenous porous media. They were positioned horizontally then saturated with synthetic brine and light crude oil as the initial condition before starting the injection scenario. The experiment was conducted at room temperature. The entire process of micromodel flooding test was monitored by camera and then for the further analysis was done using Digital Image Analysis (DIA). According to the polymer rheology and aqueous stability test, it can be proven that polymer is a non-newtonian fluid indicated by shear thinning behavior and it can be observed that FP3630S polymer is a good candidate for micromodel flooding test. The micromodel flooding result confirmed that the increasing of polymer concentration will result in higher incremental oil recovery factor. In addition, based on the final condition of the micromodel after the polymer injection process, there is improvement of sweep efficiency due to the front stability resulted by the decreasing of mobility ratio between displacing fluid (polymer solution) and the oil bank.

Compositional effects in thermal, compositional and reactive simulation

This work studies the influence of several compositional effects on thermal and reactive processes. First, the impact of using a fully compositional model in the context of thermal simulations is considered. Detailed phase behavior models rely on compositional descriptions of the oil using up to tens of components. Lumping a large number of components into a smaller number of pseudo-components in order to reduce the computational cost is standard practice for thermal simulations. Lumping schemes are typically calibrated using experimental data, in order to achieve a good approximation of the phase behavior of the initial oil. Due to the evaporation and condensation of components under thermal stimulation, the oil composition will widely vary in time and space. This works illustrates that even if the lumped schemes were able to capture the phase behavior of the initial oil, the lack of resolution can lead to modeling artefacts and/or fail to capture the relevant displacement processes. Then, the effects of different compositional interpretations of the lumped pseudo-species appearing in typical reaction schemes are investigated. A constant, mass-based fraction of the oil is allowed to react, and the reactive components are modified. Due to molecular weight effects, the reaction rate is larger when light and medium components are allowed to react. Those effects result in an increased displacement, leading to faster fronts, larger oil banks and more pressurization of the system.

ANALYSIS OF ENHANCED OIL RECOVERY IN THE PELICAN LAKE FIELD USING SURFACTANT AND POLYMER INJECTION

To analyze the economic viability of Pelican Lake field, located in Canada, some scenarios using enhanced oil recovery methods were simulated by request of the field operator, Canadian Natural Resources Limited. Surfactant concentrations influence essential characteristics responsible for promoting good recovery, lowering interfacial tension of fluids and aiding oil bank mobility. Considering different polymer and surfactant concentrations in the injection water and using the PumaFlow software, 5 (five) scenarios of fluid injection were simulated. Results show that the oil recovery factor is directly proportional to the concentration of chemical agents. Among the injection tests carried out, the one with the best performance was the case presenting a concentration of 1400 ppm of polymer and 3000 ppm of surfactant in the injected water, allowing a larger oil production from the field. The case presenting the best outcomes had a 50% higher net present value if compared to the water injection case, as well as an increase of 4.85 percent points in the recovery factor. In addition, for each barrel of additional oil produced, only USD 8.18 is spent on chemical agents, which makes it a cost-effective solution to oil production.

Polymer Retention Determination in Porous Media for Polymer Flooding in Unconsolidated Reservoir.

Polymer flooding is a well-established technique aimed at improved recovery factors from oilfields. Among the important parameters affecting the feasibility of a large deployment, polymer retention is one of the most critical since it directly impacts the oil bank delay and therefore the final economics of the project. This paper describes the work performed for the East-Messoyakhskoe oilfield located in Northern Siberia (Russia). A literature review was first performed to select the most appropriate methodology to assess polymer retention in unconsolidated cores at residual oil saturation. 4 polyacrylamide polymers were selected with molecular weights between 7 and 18 M Da and sulfonated monomer (ATBS) content between 0 and 5% molar. An improved 2-fronts dynamic retention method along with total organic carbon—total nitrogen analyzers were used for concentration measurement. Retention values vary between 93 and 444 The sentence could be rephrased μg/g, with the lowest given by the polymers containing ATBS, corroborating other publications on the topic. This paper also summarizes the main learnings gathered during the adaptation of laboratory procedures and paves the way for a faster and more efficient retention estimation for unconsolidated reservoirs.

In-Situ Combustion Frontal Stability Analysis

SummaryBecause of complex chemical reactions and multiphase flow physics, the displacement front stability for in-situ combustion (ISC) enhanced oil recovery (EOR) processes are not well understood. In this work, theory and numerical simulation validation are presented to establish an analytical frontal stability criterion for ISC processes.First, the four influencing factors for ISC displacement stability are analyzed: viscous force, heat conduction, matrix permeability changes caused by coke deposition, and gravity. A thorough analysis of the different zones and displacement fronts in a typical ISC process is conducted, and the most unstable front with the strongest tendency for gravity override is identified. Second, analytical solutions for judging the frontal stability and gravity override are established. Third, numerical reservoir simulation is performed to study the frontal stability and gravity override to validate the analytical theory. Carefully selected numerical schemes, as well as spatial and temporal discretization, are used to ensure the accuracy of these simulations.The four major zones and three displacement fronts (combustion front, leading edge of steam plateau, and oil bank leading edge) are identified in a typical 1D ISC process. The most unstable front with the largest pressure gradient contrast is the leading edge of the steam plateau. Gravity override also first takes place here with large fluid density differences across the front. By establishing material and energy balances and solving the wavy perturbation of the steam front, an analytical equation for deciding the ISC flood front stability in a 2D horizontal plane is achieved. Furthermore, the analytical solution for ISC gravity override is established. In numerical simulations, we are able to obtain results with sufficient accuracy to capture unstable ISC displacements and show fingering behavior under different conditions. The matrix permeability reduction caused by coke deposition has minimal impact on frontal stability. The simulation results are successfully validated with the analytical work for conditions in which the ISC process is stable or unstable and also for the degree of ISC gravity override. This demonstrates the predictive capability of the analytical method.In summary, a theoretical framework to analyze whether the displacement front of an ISC process is stable or not has been established. Numerical simulations confirm its predictive capability. This serves as a new reservoir engineering tool to aid the implementation and design of practical ISC projects.

Islamic Bank and Economic Growth in the World

This research has purpose to analyze (i) the influence of oil prices, profitability and banks deposit on Islamic banks growth. (ii) the influence of Islamic banks growth on economic growth. The data for this study were collected from secondary data of the 105 Islamic banks from 24 countries. This research was conducted with the period of 10 years from 2007 to 2016, therefore this method using panel data regression. The result of panel data regression with fixed effect model consisted of the variable of oil prices, profitability, bank deposit have a significant positive effect on Islamic banks growth. The other results of panel data regression with fixed effect model consisted of the variable of islamic banks growth have a significant positive effect on economic growth. The results of this study consistent with the results of previous research. This means that the high growth of Islamic banking can increase a country’s economic growth. This study gives results that can be used as reinforcement from previous studies. This research is the first research that study on the effect of the Islamic banking growth while affecting economic growth in thr World. Therefore, government intervention is needed to maintain the stability of Islamic banking and good international relations are needed to keep oil price stable.

Polymer-free viscoelastic fluid for improved oil recovery

It has been observed that alkylpropoxy sulfates, sometimes called extended surfactants, exhibit an oil-induced viscoelastic behavior. This unique behavior occurs within the Winsor III microemulsion domain where the microemulsions are deemed “oil-starved”, meaning that the oil content of the system is below the solubilizing capacity of the microemulsion. The resulting viscoelastic fluid offers dual benefits of producing both ultra-low oil/water interfacial tension (IFT) and favorable rheological characteristics such as serving as a displacing agent within the porous medium. In this work, the potential of the oil-induced viscoelastic formulations was explored in tertiary recovery application. First, the formulations were carefully tuned to achieve an ultralow IFT with the site-specific crude. Then only 4 – 6 vol% of crude oil or substitute paraffinic oil, was added with the freshly prepared aqueous solution to trigger the desired rheological behavior. The resulting fluid was then injected to the porous medium. Based on the results of 1-D glass column and 2-D Hele–Shaw cell studies, smoothly advancing of oil banks were realized shortly after injection of the viscoelastic fluids, which in turn led to fast oil breakthrough, high oil cut, and better tertiary recovery. Significant advantages of the developed viscoelastic systems are that they offer a robust system with versatile polymer-free injection package and the potential for field tertiary recovery involving a single-slug that drastically improves the volumetric sweep efficiency and the microscopic displacement efficiency, without the complex water treatment system and polymer mixing system required for surfactant-polymer (SP) or alkaline- surfactant-polymer (ASP) floods.

Heat loss effect on oil bank formation during steam flood

Heavy oil deposits are unconventional resources that are complex and challenging to produce. These unconventional resources usually require thermal recovery techniques to lower the oil viscosity and improve the mobility of it. Steam flood is a popular thermal recovery method. Understanding the mechanism of steam injection and heat utilization improves the efficiency of heavy oil recovery. In this work, the steam flood is applied to a synthetic unconsolidated sandstone core sample to mimic the Lower Fars heavy oil formation located in northern Kuwait. Experimental work was done to conduct the steam flood to this unconsolidated core sample saturated with heavy oil. The steam propagation and oil bank formation were investigated. X-ray computed tomography (CT) scanner was used during the experiment. The experimental data and X-ray CT measurements were analyzed to quantify the changes in the in-situ oil saturation during the steam flood. The growth of the steam zone was quantified and tracked by the CT images. The CT imaging reconstructions showed the formation of an oil bank and its location from the injection inlet side. The experimental observation indicated that the location of the oil bank was stationary and did not advance further at some point during the steam injection due to the heat loss effect. The analysis of the CT images showed that due to the heat loss, the oil bank size was thin. It was also observed that the steam sweep efficiency was high at the injection end. This study provides valuable information on the in-situ heavy oil saturation distribution during the steam flood for the development of heavy oil fields in Kuwait. The work is the first steam flood under CT imaging scanner facility in Kuwait and among the very few done in the world.

SEMI–PERMEABLE MEMBRANE METHOD IN DRAINING-IMPREGNATION MODE IN THE INVESTIGATION OF OIL AND GAS COLLECTORS

In the complex of petrophysical methods for studying reservoir rocks, the semi-permeable membrane method whereby the residual water saturation and the structure of the pore space are mainly determined during the modeling of the process of produced water displacement by gas during the deposit formation, is quite widely used. In this case, the membrane operates in drainage mode. To address issues that arise during the oil and gas fields development, the reverse process is also of interest - modeling the reverse water flooding of the pore space when the gas pressure in the deposits decreases or during forced water flooding of the deposits, or when studying the processes of selective water flooding of wells. In this case, the membrane should work in the drainage mode for the first part of the experiment, creating residual water saturation, and.it should work in the impregnation mode fo rthe second part of theex periment. The drainage mode is described in sufficient detail in the literature, there are practically no materials on reverse impregnation. The carried out work was aimed at developing a semi-permeable membrane method for the drainage-impregnation regime to the extent of practical use, including carryingouta small number of test studies. The developed methodology will be explained in complete detail in the corresponding methodological manual, mainly its problematic aspects are considered here. Further application of the developed methodology will be aimed at solving specific problems arising in the process of hydrocarbon deposits development. Among the priority objects of study are the processes of gas displacement by oil from oil banks, oil displacement by water, oil and gas mixture displacement during the cycling process.

Numerical simulation of impact of biopolymer production and microbial competition between species on performance of MEOR process

In this work we look at MEOR processes including biopolymer production and microbial competition. We have simulated a two-phase system containing of oil, water, nutrients, metabolite (biopolymer) and biofilm using the Matlab Reservoir Simulation Toolbox (MRST) package. Different mechanisms including water viscosity improvement by the action of biopolymer and biofilm formation due to adsorption of bacteria was studied. The effect of microbial competition due to presence of indigenous bacteria on the performance of MEOR process was also studied. Results shows that the presence of biopolymer improves the oil recovery in comparison with pure waterflooding. The biopolymer improves the recovery by creation of a traveling oil bank within the reservoir. Further analysis is performed to evaluate the influence of a high permeability thief zone to the model. The presence of indigenous microbes has been revealed to limit the MEOR displacement efficiency in both MEOR and thief zone simulations.