محمد سیم جو

One of the leading challenges in developing heavy oil fields through water-based injection methods is early production of injected water and insufficient oil production. This event can result from unfavorable conditions of mobility, which is aggravated by the heterogeneity of the reservoir. In such a situation, polymer injection can provide a favorable potential for improving water-based injection methods. In this study, an analytical model has been developed to quickly predict the flow behavior of polymer solution at the core (fine) and reservoir scales. Moreover, to achieve this goal, first, an analytical model based on the Buckley-Leveret theory at the core scale was presented to design polymer flooding and to investigate the influence of the governing mechanisms on increasing oil recovery. Then, at the reservoir scale, the effect of heterogeneity in the form of the Koval parameter and the effect of salinity (seawater salinity and its diluted conditions) on the performance of the polymer injection methods were considered. According to the core scale results, polymer injection led to a 7% increase in oil recovery compared to seawater injection. In heterogeneous reservoir conditions, this positive performance was more significant and led to 12% additional oil production compared to seawater. Ultimately, regarding the effect of salinity, the obtained results showed the synergism of the low-salinity polymer flood method in such a way that, in the core and reservoir conditions, oil production was 12 and 4 percentages higher than that of polymer injection. Moreover, the developed analytical model is a suitable tool for designing the polymer flood process in different conditions of salinity and heterogeneity, which can be used to facilitate technical and economic decisions at the reservoir scale.

Decision-making to choose the best Enhanced Oil Recovery (EOR) method(s) among different variety of models, is a vital step in the oil reservoir development process. Selecting the proper EOR method has a key role in the technical and economic success of enormous oil industry projects. Screening criteria are used for selecting the best EOR method(s) for an oil reservoir with specific rock and fluid properties. The main input parameters that affect the screening process include; Reservoir capacity, fluid transmissibility and permeability, depth, net thickness, temperature, and oil gravity (API). Considering mentioned parameters have uncertainty, specifying a suitable EOR method for reservoir development is a radical challenge. It can be used combination of fuzzy logic systems (knowledge base) and artificial neural networks (data-driven) as a suitable tool and solution for expressing uncertainty and screening methods. In this study, data from the history of different reservoirs worldwide is used to define fuzzy variables and determine fuzzy rules between input and target variables, and finally, a fuzzy model and a single-layer neural network with 20 neurons are presented. ANN model provides 92% accuracy in the prediction of the target method. Consequently, we proposed the ensemble model for the selection of the EOR screening tool.

Considering the need for excessive consumption of hydrocarbon resources and gas fuel supply in the cold seasons of the year, it has been suggested to use the drained oil and gas reservoirs and underground water aquifers to be used as natural gas storage reservoirs. Among the influential factors in natural gas storage are the reactions between fluid-fluid and fluid-rock, which is the most important of these wettability factors. Knowing these factors in the gas storage process will lead to better control and storage of natural gases in geological structures. Underground water aquifers are one of the structures with favorable conditions for natural gas storage which by wettability alteration to gas wetness in these, can be increased the natural gas storage capacity. For this purpose, this study has investigated the laboratory works done on the distribution and behavior of fluid in the samples of carbonate and sandstone in order to wettability alteration to gas wetness for the purposes of underground gas storage.

Fossil fuels are considered the main factor of global development, but reaching the goals of zero carbon and carbon-free economy will push the world towards new energies, including hydrogen. Hydrogen as an energy vector and a clean energy carrier with carbon-free combus tion is proposed as a suitable method to meet the global energy demand. However, in order to achieve the desired goals, there is a need for hydrogen s torage on a large scale. Generally, underground tanks are considered the bes t places for hydrogen s torage in large scales. The parameters that control hydrogen s torage in underground formations are important and should be extensively s tudied. Until today, research has been done in relation to these influential parameters, whose findings have been examined in this s tudy, but considering that underground hydrogen s torage sys tems (UHS) are in their initial s tages, there is a need for more extensive research. Therefore, this review can be a source for researchers who research UHS.

Interfacial tension (IFT) is one of the most important parameters that directly affects the capillary forces, which affects oil recovery. This research investigates the effects of asphaltene concentration and water-soluble divalent ions on IFT. A mixture of toluene and n-heptane, which is called heptol, is used as the model oil, and then asphaltene was added into Heptol to study its effect on the surface-active properties of the model oil. Brine in a salinity of sea water (SW) with a concentration of 40,000 ppm was considered as the base aqueous phase. A diluted brine with a concentration of 4000 ppm was prepared as a low salinity water (LSW), and a concentrated 80,000 ppm aqueous solution is considered high salinity water (HSW). Afterwards, the dynamic IFT of the oil phase/aqueous phase interface was measured using the pendant drop method. Results show that with the increase in the asphaltene concentration, IFT of heptol/brine system was decreased. The lowest value of IFT was observed in the salinity of 40,000 ppm. This may show an optimum salinity range to facilitate migration of asphaltene molecules into brine/heptol interface, which led to an IFT reduction from 23 to 16 mN/m. Results indicated that an asphaltene concentration of 0.5% can be was considered as the critical micelle concentration. At the end, the effect of divalent ions, i.e. calcium, magnesium and sulfate ions in the aqueous phase was investigated, and it is shown that the calcium ion has a larger effect on IT reduction compared to the magnesium and sulfate ions.

In this work, a reliable mathematical model for numerical modeling of co-current and counter-current spontaneous imbibition in 1D and 2D modes is presented using MATLAB software and validated. Then, several studies are conducted on the effect of boundary conditions on the imbibition process. Results show that the oil recovery in co-current imbibition was 1.5 times greater than counter-current imbibition after 20 days. The results also show that in blocks with different heights, oil recovery is different. Investigation of the counter-current spontaneous imbibition in 2D mode in a large matrix block fully immersed in water indicated the effect of the gravity force in doubling the oil recovery after 120 days. Moreover, reducing the matrix block-water contact results in a decrease in the performance of imbibition process in the oil production so that the amount of the counter-current imbibition oil recovery decreased from 49% (four faces in contact with water) to 30% (one face in contact with water) after 10 days. The results show the increase of the water-contacted boundaries improves the spontaneous imbibition process efficiency.

In gas injection processes, due to a large viscosity contrast, sweep efficiency is incomplete and large volume of oil is left behind in the reservoir. Polymer alternating CO2 gas (CO2-PAG) injection can be used to improve sweep efficiency and increase oil recovery. This method benefits form an improved microscopic displacement with the injection of gas, and an enhanced macroscopic sweep efficiency with the injection of polymer. To the best of our knowledge, this method has not been studied in the micr scale. The purpose of this study is to investigate the mechanisms of oil production in the CO2-PAG injection process using glass micromodels. Two-dimensional water-wet micromodel with a diagonal injection-production pattern was utilized to visualize the pore-scale oil recovery mechanisms. The micromodel was well equipped with a high resolution camera to capture microscopic phenomena during the oil displacement. A paraffinic model oil with a viscosity of 0.028 Pa.s was used as the representative of viscous crude oil. Moreover, partially hydrolyzed polyacrylamide with a concentration of 1500 ppm was used to control the mobility of the aqueous phase. Initially, the micromodel was saturated with saline water i.e., fully saturation, then oil was injected to achieve an irreducible water saturation. Afterwards, to investigate the EOR potential of CO2-PAG, the alternate cycles of gas and polymer were injected at two PAG ratios of 1:1 and 2:1. Microscopic phenomena affecting oil displacement during the process of CO2-PAG injection were investigated. Therefore, it was possible to identify several effective mechanisms that improve oil recovery. Results show that both the formation of mobile gas clusters and polymer elasticity increased oil recovery. Mobile gas clusters caused double drainage and imbibition in the micromodel system. A pore to pore oil displacement by polymer solution, the formation of continuous and discontinuous polymer strings, the existence of mobile blobs and gas clusters were observed and identified during the CO2-PAG injection process. Results confirmed that an improvement in the volumetric sweep efficiency was achieved by the CO2-PAG injection. In 1: 1 PAG ratio, a higher volume sweep efficiency was obtained.

Efficient drilling cuttings transport is one of the most important parameters affecting drilling rate of wells. Foam has a great potential to reduce drilling problems compared to conventional well drilling fluids due to its unique properties such as low density and high viscosity. Proper description of foam behavior enables us to improve the performance of foam for hole- cleaning. In this paper, cuttings transport using foam was studied using a computational fluid dynamics approach. In this study the Eulerian multi-phase model was used to describe cuttings-fluid mixture flow. Foam rheology was expressed by the non-Newtonian power law model. Effects of foam quality and injection velocity, cuttings size, pipe eccentricity and rotational speed of drillpipes were studied. Modeling results were also compared with experimental data. Results showed that increase of foam quality improved hole-cleaning operation mainly due to the enhanced foam viscosity. Increase of foam injection velocity led to a reduction in in-situ cuttings concentration. This was due to the foam capability to destruct stationary cuttings bed. Accordingly, as foam injection velocity increased from 3 to 5 ft/s, cuttings concentration decreased by 1.3 times. Also, an increase in the size of the cuttings caused a poor well cleaning. It was found that pipe eccentricity resulted in the accumulation of cuttings in the wellbore annulus. But, increase of the drillpipe rotational speed provided a better hole-cleaning, so that by increasing the rotational speed to 40 RPM, cuttings concentration decreased by 1.8 and 1.4 times in concentric and eccentric pipe, respectively.

As oil fields approach to the end of the primary production phase, the new technologies should be employed to increase the recovery of hydrocarbons. In recent decades, nanofluid has been proposed as an efficient, and environmentally friendly approaches for EOR purpose. The target of this study is to investigate the effect of silica nanoparticle on the wettability alteration of the carbonate rock. In this study, four different concentrations of silica nanoparticle were used (0.01, 0.02, 0.05, and 0.1 wt.%) in low salinity seawater (1000 ppm of positive ions). The stability of nano particle in brine is one of the challenge while using for EOR. In this study the stability of nano fluid was achieved without using any surfactant. The Spontaneous imbibition experiments, and contact angle measurements were carried out at 75 °C to check the performance of nano fluids in wettability alteration of carbonate rock. The results showed that the silica nanoparticle has a significant effect on the oil recovery from carbonate rock. The diluted sea water (1000 ppm) without nano particle resulted to the oil recovery of 10.45% whereas nano fluid with concentration of  0.01, 0.02, and 0.05 wt.%  resulted to the oil recovery of 11.5%, 10.83%, and 22.16% , respectively. The contact angle results also confirmed that the silica nanoparticle has a positive effect on the wettability alteration of the carbonate rock surface toward water wetness. The permeability measurement after and before spontaneous imbibition tests showed that the pores were not blocked due to nano particle precipitation. The impact of initial water in the rock was investigated on the performance of wettability alteration while using nano fluid. The results depicted that the presence of initial water in the carbonate rock adversely affect the oil production.

DME-enhanced water flooding is considered as a novel enhanced oil recovery method. In this method, DME-rich water is injected into an oil reservoir. In addition, upon the contact of DME-rich water with trapped oil in the reservoir, DME partitions between the oleic and the aqueous phase. Due to the partitioning process DME transfers from the aqueous phase into the oleic phase until reaching a thermodynamic equilibrium. Consequently, two zones are generated in the oleic phase: 1- an interface region, which is DME-rich, and 2- the DME-free zone, which is far from the interface. The variation of DME concentration in the oleic phase causes a DME transfer from the DME-rich zone into the DME-free zone due to the molecular diffusion. The DME dissolution in the oleic phase causes an oil swelling process and thus an increase in the saturation of the oleic phase along with oil viscosity reduction. Moreover, both effects improve the oleic phase mobility leading to a more favorable oil displacement efficiency in porous media. The present work demonstrates the feasibility of application of DME-enhanced water flooding in recovery of heavy oils via a 1D modelling study. Therefore, several pieces of work were performed to achieve proper results. First, mass conservation of components was combined with the Darcy equation while using a constant partition coefficient (linear PVT model) to obtain governing fluid flow equations. Then, the system of equations was completed using auxiliary equations and equations were combined to reduce the number of independent variables. Afterwards, equations were numerically solved using a finite difference scheme to find the independent variables, i.e. pressure and saturation of the aqueous phase, and also concentration of DME in the aqueous phase. Numerical modeling results showed that the use of DME-enhanced water flooding improves oil recovery in heavy oil reservoirs. For instance, the DME-enhanced water flooding led to an additional oil recovery of 17 percent of the OIIP on top of water flooding oil recovery. Moreover, results showed the injection of DME-water into the porous media causes the formation of an oil bank and also a reduction in the water cut. Furthermore, it was shown that a part of DME can be recovered at the injection well, and this can affect the project economy positively. Finally, the results showed the potential application of DME in the recovery of heavy oil.

Low salinity water (LSW) flooding is one of the emerging EOR methods which has recently attracted lots of attention. Wettability alteration from oil-wet to water-wet triggered by ion exchange between low salinity water and rock surface is one of the dominant mechanisms to increase oil recovery by LSW. This paper studied the performance of LSW flooding in a sandstone oil reservoir where wettability alteration was investigated by coupling two-phase flow equations and geochemical reactions between water and rock surface. A wettability alteration index based on the ion equivalent fraction of sodium was introduced that mainly consists of the effects of ion exchange and clay properties on oil/water relative permeability functions. Also, the effect of calcite mineral dissolution was investigated by the relevant geochemical reactions. Results showed that salinity difference between injected and formation water caused ion exchange processes between water and rock surface. Also, calcite dissolution enhanced ion exchange processes and thus led to wettability alteration to more water-wet conditions. Results showed that the presence of dissolved CO2 in water increased the rate of calcite dissolution. It was also found that the rate of ion exchange and calcite dissolution reactions decreases far from the injection well. The results of this study revealed that LSW flooding provided incremental oil recovery of 8% of the oil initially in place as compared to high salinity water flooding.

According to the positive results of low salinity water (LSW) flooding to recover incremental oil, different studies have been performed to investigate the combination of LSW and other enhanced oil recovery (EOR) methods. Combination of polymer flooding and LSW could be one of the most effective EOR methods. Taking into account the strength and weakness of each individual method, one can take advantage of the synergism between polymer and LSW: presence of polymer improves oil sweep efficiency and LSW decreases polymer adsorption and alters rock wettability to more water-wet. In this paper, we applied fractional flow theory to investigate the performance of polymer-associated low salinity water (LSP) flooding as an EOR method in sandstone reservoirs. Also, application of LSP flooding to recover incremental oil was compared to that of high and low salinity water flooding. The results showed that as LSP was injected into the given sandstone reservoir, there is a delay in water breakthrough time to as much as 0.75 PV. Also, oil recovery duet to the LSP injection increased from 38% to 77% as compared to high salinity water flooding after 1 PV injection. Fractional flow analyses showed that the incremental oil obtained by LSP is mainly due to the presence of two distinct water saturation shock front.

One of the enhanced oil recovery methods that has been recently received more attention is low salinity water injection (LSW). Among the proposed mechanisms to describe LSW, geochemical reactions seem to mainly affect rock wettability alteration and thus incremental oil recovery. The goal of this paper is to investigate the effect of geochemical reactions of calcite dissolution and ion exchange on the performance of LSW in a sandstone reservoir by using the concept of threshold salinity. Fluid flow equations according to Buckley-Leverett theory were numerically coupled with the PHREEQC software. Results showed that as LSW was injected, initial equilibrium between reservoir rock surface and aqueous phase was disturbed leading to calcite dissolution and also cation exchange between aqueous phase and rock surface. Analysis of geochemical reaction near the injection well showed that cation exchange may cause to separation of organic compound from rock surface leading to wettability alteration to more water- wet. Also, pH profile through the reservoir showed that rate of calcite dissolution was very high near injection well, but only partial dissolution of calcite induced by cation exchange occurs at farther distance. Fractional flow analyses in line with total salinity profile showed that two distinct saturation shock fronts were established during LSW injection: first one represents high salinity condition with a water saturation of 0.43, and the second one represents low salinity condition with a water saturation as much as 0.58. Under the conditions of this study and selection of a salinity threshold of 3000 ppm, such increase of water saturation reveals EOR potential of LSW by which an incremental oil recovery of 10% of the oil initially in place was obtained as compared to high salinity water injection.

Generally, gel polymers are an appropriate method for increasing the rate of production of the oil reservoirs. To analyses the effects of gels on the oil reservoirs we will not only need to perform several experiments for determining of gel properties, also require to examine gel motion through the porous media by making use of a simulator software. In this paper a two dimensional, two phase (oil & water) permeability modification modeling developed by including a gelation model into a fluid flow equations. The partial differential equation of motion if the flow & gelation model in porous media one first discretized and then transferred into the non linear-couple algebra equations. The equations will be solved numerically. The results of simulation show the permeability modification in porous media for 5 years. This model is an appropriate mathematical model for examination of both permeability reduction and water production rate effects in porous media; also the permeability modification due to the gel injection in a porous media will be analyzed by using the Civan's power low. Ultimately, the results obtained are compared with experimental data for one of the Iranian Asmari reservoir, which shows a desirable accuracy of the presented mathematical model.