mohammadhossein ghazanfari

PPG with mesh size 40-50 in 100-time diluted sea water, showed the maximum swelling capacity. Presence of 0.8 wt% nno silica in the geAInjection of preformed particle gels (PPG) into fractured reservoirs is one of the most effective methods in reducing unwanted water production and increasing oil recovery. In this research, a sample of PPG has been synthesized by free radical polymerization method, and its performance for the conformance control has been evaluated. The swelling capacity of the synthesized gel has good stability against the desired conditions of temperature, salinity, pH and the presence of carbon dioxide. Also, due to the presence of hydrophilic organic groups, the interactions of oil and formation water lead to an increase in the swelling ratio of gel particles. The plugging performance of synthesized PPG samples in fractures was also investigated by the Hele-Shaw Cell system. The gel network placed in the fracture create a new porous media with far less permeability than the initial fracture. The ability of the gel to maintain the permeability of this formed porous medium depends on the flow rate and salinity of the secondary water injection, as well as the size of the gel particles. Secondary water injection into the fracture after gel placement, forms wormhole-like paths for flow of water through the gel network, and the higher the injected flow rate results in the lower resistance of the gel network against water flow. Gel particles with a matching size ratio (the ratio of the diameter of the swollen gel particles to the width of the fracture) less than 2.9, increase resistance to the water flow with increasing in their size, but the particles with a matching size ratio of 2.9 or higher, reduce the resistance to water flow due to network breakdown. Comparing this value with some of the previously published data, it seems that the critical matching size ratio is independent on gel properties and injection conditions. Finally, the effect of gel treatment in reducing water production and increasing oil recovery has been investigated in the fractured micromodel. The gel particles plugged the fracture and the secondary injected brine was sufficiently diverted towards matrix, so the oil recovery factor from matrix in subsequent water flooding increased by 65%.structure enhanced the stability of the synthesized PPG samples, in the high salinity brines and in the presence of the CO2. Presence of water-soluble fractions of oil, leads to 6 unit increase in the swelling ratio of gel particles due to the hydrophilic nature of these organic groups. The gel network placed in the fracture create a new porous media with far less permeability than the initial fracture. The ability of the gel to maintain the permeability of the formed porous medium depends on the flow rate of the secondary water injection, salinity and the size of the gel particles. Secondary water injection into the fracture after gel placement, opens wormhole-like paths for moving through the gel network, and the higher the injected flow rate, the lower the resistance of the gel network against water flow. Gel particles with a matching size ratio (the ratio of the diameter of the swollen gel particles to the width of the fracture) less than 2.9, increase resistance to the water flow with increasing in their size, but the particles with a matching size ratio of 2.9 or higher, reduce the resistance to water flow due to particle breakdown. This critical matching size ratio is independent of gel properties and injection conditions. The gel network swollen in more salinity has a higher resistance to water flow, while the secondary low salinity water injection, although it reduces the gel strength, but leads to an increase in the resistance of the gels to water flow. In the fractured micromodel test, the oil recovery factor from matrix increased from 29% in the primary fooding to 94% at the end of the secondary flooding.

Estimation of the breakthrough time of injected fluid in water injection process is useful for process design and injection pattern during reservoir development. Conventional approach to this is to use reservoir simulation. An alternative is to use percolation theory approach. However, some of the assumptions used in developing the scaling function of breakthrough time such as similarity of viscosity of both injection and production fluids limits its applications to field scale. In this study, we use the dimensionless time approach for breakthrough which is based on a characteristic time. By using various reservoir simulation cases the effect of fluids viscosities was studied. The results showed that the suitable characteristic time for scaling of breakthrough time depends on both NTG and viscosity ratio of phases in a power law form with exponent of 1.3.

In waterflooding process, the time for breakthrough of injecting fluid into a production well is of great importance. Predicting this time helps in designing reservoir development plan. Due to uncertainties in reservoir characterization, estimating the breakthrough is not easy, so alternative methods to estimate quickly the breakthrough time is useful. The percolation method uses limited available reservoir data to predict the breakthrough time distribution, and it may be used for engineering applications. However, implementation of this to real reservoirs requires some adjustments. The aim of this study is to show how percolation approach can be used to real problems. In particular, the effects of permeability contrast between the reservoir and non-reservoir parts in the model are investigated. In order to use the breakthrough scaling function to more realistic reservoir models, a dimensionless breakthrough time was used. The analysis of the breakthrough time of models with zero permeability background (tk=0) and such time for the case of non-zero permeability background (tk=αk) shows a linear dependency which can be used to find breakthrough time distribution. Hence, this correction extends the applicability of the percolation method for predicting breakthrough time when permeability of the system background is not zero.

The liquid bridge is considered a good means to maintain capillary continuity between overlying matrix blocks if its stability in fractures is preserved. Despite several studies focusing on the liquid bridge in different environments, little attention is paid to dig through a single liquid bridge between thin sections of minerals found in fractured reservoirs. In this study, a set of experiments was conducted to investigate liquid bridge stability and surface profile for different values of liquid volume and surface wettability conditions. It is found that critical fracture aperture is linearly proportional to the contact angle and to the third root of liquid volume, which is depicted by a newly developed expression. An accurate method for computation of capillary pressure of liquid bridge (known as fracture capillary pressure) from the experimentally determined interface profiles, based on the numerical solution of the Young-Laplace equation, is proposed. Following the Plateau sequence, both nodoid and unduloid shape bridges are observed with an increase in fracture aperture, corresponding to positive and negative fracture capillary pressure, respectively. It is interesting to note that instability of liquid bridges occurs at small negative values of capillary force where some attraction force exists between fracture faces. By applying a 1D mathematical model of liquid dripping, a modified expression for the prediction of critical fracture aperture is proposed, including fluid and flow-related parameters. The findings of this study help to better incorporate the role of liquid bridge and corresponding fracture capillary pressure in capillary continuity in fractured porous media.

Molecular diffusion is the controlling mechanism for oil recovery from fractured reservoirs with low permeable and low height matrixes during gas injection process. However, the application of conventional models for simulation of molecular diffusion process faces with some limitations. The main purpose of this study is to investigate the performance of different diffusion molecular models for oil recovery from fractured reservoirs during gas injection process and compare the results with a commercial simulator. Therefore, the models are introduced and implemented as a simulator, then the prepared simulator is validated by experimental data. Lastly, the developed simulator is applied for evaluation of CO2 and methane injection in one matrix block. The difference among the results of different models is based on using irreversible thermodynamic for calculating component concentration in gas-oil interface, using matrix form of molecular diffusion coefficients and using chemical potential gradient as the driving force in generalized Fick and Maxwell-Stefan verse classical Fick. In addition, the results of commercial simulator are near classical Fick model results because of same formulation. Also, mole fraction of methane and CO2 and oil viscosity verse time are compared for gas injection. Finally, the result of this work demonstrates that using classical Fick’s law or the commercial simulator for forecasting oil recovery from fractured reservoirs when the molecular diffusion is the main mechanism is not accurate, so generalized Fick and Maxwell-Stefan are more efficient models.

In this study, application of ultrasound wave for permeability enhancement of reservoir rocks was experimentally examined. In this regards, a specific core holder apparatus was designed with the ability of in-situ exposure of ultrasound to the plug at high-pressure condition, which is a better representative of ultrasound application in real wellbores. The effect of ultrasound power and exposure time as well as probe-plug distance on permeability stimulation was evaluated. The results showed that ultrasound could stimulate the permeability of asphaltene-damaged rocks, in which its efficiency is significant in sandstone rock. Analysis of asphaltene content in the output fluid showed that, as the result of ultrasound exposure, 84% of deposited asphaltenes in the sandstone plug was removed, which is corresponding to 67% of permeability recovery. It was also found that the stimulated permeability increases with increasing exposure time and power while decreases with increasing probe-plug distance, however an optimum value for exposure time and power, after which the permeability recovery is not significantly enhanced, was observed. Analysis of experiments also showed that probe-plug distance has the most prominent effect on recovery of damaged permeability in comparison to ultrasound time and power.

This paper presents rheology, stability and filtration loss characteristics of Colloidal Gas Aphron (CGA). Eight rheological models are applied for investigation the rheological behavior of CGA based fluids and proper model are chosen in which best described the rheological properties of CGA based Fluids. Stability analysis of CGA based fluids is examined by measuring drain rate technique. Also, Standard API filtration test were applied for investigation of the CGA based fluid loss in this study. Moreover, Rheological parameters such as fluid flow index, fluid consistency and yield point were determined. The results of the experiments show that both SDS and CTAB surfactants were improved the properties of the CGA based fluids in which SDS anionic surfactant has a better performance compared to CTAB cationic surfactant.

Although there have been several models for predicting the asphaltene-induced permeability reduction, the present study investigates the hydrodynamic effects of asphaltene deposition in the porous media with a novel and partially analytical approach. In order to find the amount of permeability reduction, we have modeled the variations of hydraulic radius. The main idea for modeling the permeability reduction is the fact that by deposition of the particles, the available void space is reduced. Also, the drag force between the particles and the fluid reduces the flow potential. In this paper, using the size variation of the asphaltene particles during flocculation, with assuming that the size distribution is equal inside and outside the porous medium, permeability reduction is obtained and matches with the existing experimental results. Modeling is done using MATLAB and a code is written for calculating the permeability reduction due to formation damage. This model is partially analytical and do not use numerical estimations, thus it is flexible to be applied for other formation damage problems. In addition, this modeling can predict the deposition process if the changes of the particle size distribution is known as a function of time.

Surfactant flooding is known as an essential and important method for enhancing oil recovery from carbonate reservoirs. High amount of Adsorption of some surfactants onto carbonated surfaces makes some difficulties in accurate prediction of oil recovery efficiency in this type of injection process. In this paper, the adsorption of nonionic surfactant Triton x-100 on the surface of the carbonate rock is experimented. The carbonate rock is crushed and contacted with surfactant solution, and the amount of the surfactant adsorption on the surface of the carbonate rock is measured after arriving the equilibrium condition. It is observed that the adsorption of the surfactant is saturated at about 500 ppm. Also, the adsorption results matched well with the Langmuir model. The amount of Langmuir constant is obtained 173.34 gr sol / gr surf and the maximum adsorption is obtained 19.23 mg surf /gr rock. Comparing the adsorption data shows that the amount of surfactant adsorption and its variations especially above the critical micelle concentration in carbonate rocks is greater than sandstones. So, it is more important to consider the surfactant adsorption and its waste during surfactant injection and its simulations in carbonate reservoirs.

In this paper, a very efficient method, called single matrix block analyzer (SMBA), has been developed to determine relative permeability and capillary pressure curves from spontaneous imbibition (SI) data. SMBA mimics realistically the SI tests by appropriate boundary conditions modeling. In the proposed method, a cuboid with an identical core plug height is considered. The equal dimensions of the cuboid in x and y directions are set such that the cylindrical core plug and the cuboid have the same shape factor. Thus, by avoiding the difficulties of the cylindrical coordinates, a representative model for the core plug is established. Appropriate grid numbers in x-y and z directions are specified to the model. Furthermore, the rock and fluid properties of SI test are set in the SMBA. By supposing forms of the oil-water capillary pressure and relative permeability and comparing the oil recovery curves of SMBA and SI data, capillary pressure and relative permeability can be determined. The SMBA is demonstrated using three experimental data with different aging times. Suitable equations are employed to represent the capillary pressure and relative permeability curves. The genetic algorithm is used as the optimization tool. The obtained results, especially for capillary pressure, are in good agreement with the experimental data. Moreover, the Bayesian credible interval (P10 and P90) evaluated by the Neighborhood Bayes Algorithm (NAB) is quite satisfactory.

In this work, the process of free gravity drainage under the influence of ultrasonic waves was investigated. A glass bead pack porous medium was used to perform the free fall gravity drainage experiments. The tests were performed in presence and absence of ultrasonic waves and the data of recovery were recorded versus time in both conditions. The wetting phases relative permeability curve were obtained using the data of recovery versus time based on the Hagoort backward methodology and afterward, using the wetting phase relative permeability curve, the relative permeability of non-wetting phases were calculated by performing history matching to the experimental production data. The results revealed that ultrasound considerably increases the recovery factor of the free gravity drainage process. It was also observed that the relative permeability of both wetting and non-wetting phases increases under exposure to ultrasonic waves. The results of this work can be helpful to better understanding/evaluating the behavior of relative permeability curves of both wetting and non-wetting phases during free gravity drainage process under the exposure to ultrasonic wave.

It has been proved that ultrasonic energy can considerably increase the amount of oil recovery in an immiscible displacement process. Although many studies have been performed on investigating the roles of ultrasonic waves, based on the best of our knowledge, little attention has been paid to evaluate wave attenuation parameter, which is an important parameter in the determination of the energy delivered to the porous medium. In this study, free fall gravity drainage process is investigated in a glass bead porous medium. Kerosene and Dorud crude oil are used as the wetting phases and air is used as the non-wetting phase. A piston-like displacement model with considering constant capillary pressure and applying Corey type approximation for relative permeabilities of both wetting and nonwetting phases is applied. A pressure term is considered to describe the presence of ultrasonic waves and the attenuation factor of ultrasonic waves is calculated by evaluating the value of external pressure applied to enhance the flow using the history matching of the data in the presence and absence of ultrasonic waves. The results introduce the attenuation factor as an important parameter in the process of ultrasonic assisted gravity drainage. The results show that only a low percentage of the ultrasonic energy (5.8% for Dorud crude oil and 3.3% for kerosene) is delivered to the flow of the fluid; however, a high increase in oil recovery enhancement (15% for Dorud crude oil and 12% for Kerosene) is observed in the experiments. This proves that the ultrasonic waves, even when the contribution is not substantial, can be a significantly efficient method for flow enhancement.

Finger initiation/developementat fluid-fluid interface during miscible floods can cause poor displacement efficiency, which is undesirable in enhanced oil recovery processes. In this work a series of hydrocarbon injection experiments performed on 5-spot glass micromodels which were initially saturated with the heavy crude oil. The fractured micromodels with different fracture geometrical characteristics used in the tests. High quality image analysis applied to determine the fluid flow behaviour, solvent front movement and viscous fingering associated with solvent movement in matrix and fractures. Observations showed that higher solvent dispersion in the fractures rather than matrix in both longitudinal and transversal directions cause the finger behaviour to be affected by the fracture geometrical characteristics. It also diminishes and merges the fingers to a unit solvent front by increasing spreading in regions near fractures. Due to the heterogeneity induced by fractures in media finger tip splitting initiates before solvent breakthrough. In fact longitudinal dispersion improves shielding, while transversal dispersion increases the fingers spreading and splitting. In addition, it has been revealed that splitting, before and after breakthrough, as well as spreading in regions near fractures is directly proportional to the fracture scattering, fracture discontinuity and fracture density of the medium. Also, it has been found that shielding phenomena is mostly affected by fracture orientation which its maximum occurrence is for the case of zero degree to average flow path. The results of this work can be helpful to better understanding of viscous fingering behaviour, which is crucial for accurate prediction of oil recovery, in fractured reservoirs during miscible displacements.

In this work a glass micromodel which its grains and pores are non-uniform in size, shape and distribution is considered as porous medium. A two-dimensional random network model of micromodel with non-uniform pores has been constructed. The non-uniformity of porous model is achieved by assigning parametric distribution functions to pores throat and pores length, which was measured using image analysis technique. Statically derived expressions have been used for prediction of macroscopic properties of porous model including: dispersion coefficients, permeability-porosity ratio and capillary pressure. The results confirmed that predicted transport properties are in good agreement with the available experimental data