مجله پژوهش نفت
پیاپی 92 (فروردین و اردیبهشت 1396)

Fractured carbonate reservoirs constitute considerable number of hydrocarbon reservoirs in Iran. In the fractured reservoirs, the gravity drainage is one of the dominating oil producing mechanisms, which controls oil production depending on the interaction between upper and lower blocks. However, in few theoretical studies have investigated the modelling of re-infiltration process between stack of matrix blocks. In this study, at first the gravity drainage process is modelled for a 1-D single matrix block by consideration of gravity and capillary forces, then Laplace transform is used to solve the governing partial differential equation related to matrix blocks, with the appropriate initial and boundary conditions. Moreover, the obtained equations are extended to a stack of matrix blocks and the effect of re-infiltration process in investigated. The inlet oil from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the determined saturation equations, oil production rate, cumulative production, the gravity drainage mechanism and the effect of re-infiltration process are studied. It is worth mentioning that proposed solution for re-infiltration problem in this study is fully analytical, while previous proposed solutions from other researchers (Firoozabadi and Ishimoto [1]) have been numerical or semi-analytical.

Natural fractures’ network are important in determination of hydraulic behavior of oil and gas reservoirs. Fractures are invaluable in hydrocarbon production, especially in naturally fractured carbonate reservoirs. The effective permeability of Asmari carbonate reservoir is highly dependent on the occurrence of open fractures. In this research, 409 open fractures, derived from image logs of six wells were used to determine fractures’ sets considering Fisher coefficient. The fractures are categorized into seven fractures sets. The variety of fracture sets is an indicator of reservoir heterogeneity. Although the wells are located on the southwestern plunge, the general pattern of fracture in the field is longitudinal. A possible explanation for this phenomenon is change in stress direction during folding. After determination of the fractures’ properties for each fracture set, discrete fracture network model was created. The average orientation of fractures in the test well, which was not used in the DFN model, was identical to the fracture orientation of the DFN model in the location of the well. In the test well, observed reservoir pressure, 2299 psi, (from well test) was matched to the 2294.62 psi of the model.

The Geophysical Strata Rating (GSR), which is introduced in this study for carbonate reservoirs, is an empirical strength rating of rocks. It provides ratings from 10 to 100 where the lower values correspond to rocks; such as, shales which are weak from a borehole stability point of view and also the porous, permeable reservoir rocks. In comparison, the higher values of GSR are associated with intact rocks with few defects in the form of fractures and discontinuities and low porosity. In this study, GSR is calculated from petrophysical data using the equations developed in clastic rocks. The region investigated is the South Pars gas field where the Permo-Triassic Dalan and Kangan reservoirs host the largest accumulations of gas in the world. The GSR results are in good agreement with porosity and elastic moduli of these carbonate rocks. Discrimination between reservoir and non-reservoir shaly units would easily be obtained by comparing GSR and well logs. Very low GSR values, with high gamma ray log responses, indicate the shaly intervals. These can cause washouts, casing collapse and other related drilling problems. Intervals with low GSR values and low gamma ray log responses indicate the presence of good reservoir units. Finally, a 3D GSR model is estimated from 3D post-stack seismic data of the South Pars gas field, by using a probabilistic neural network model. Strong correlations between neural network predictions and actual GSR data at unseen borehole locations proved the validity of the intelligent model in GSR estimation. This 3D GSR cube can be utilized for construction of geomechanical models over the South Pars gas field.

Some geomechanical changes may be occurred due to the production and gradual depletion of the reservoir. Fracturing in depleted reservoirs is studied in this article. In depleted reservoirs, there are three kinds of scenarios for fracturing. A fault may be created as a result of production. Drilling a depleted reservoir is sometimes necessary to reach to deeper targets. Pore pressure variation changes safe mud window. Hence, some fractures can be generated in drilling with previous mud weight, and then mud lose is occurred. In addition, the third kind is hydraulic fracturing in depleting reservoirs. Decrease of pore pressure is a willing factor, and a hydraulic fracture can be generated with less pump pressure. In this article, the possibility of the horizontal stresse rotation is studied. Stress rotation can help fractures to reach to new parts of reservoirs which remain undrained. At last with usage of geomechanical parameters of one of the reservoirs of south Pars field, the possibility of faulting and stress rotation is predicted.

One of the common methods of enhanced oil recovery in naturally fractured reservoirs is gas injection. The majority of Iranian hydrocarbon reservoirs are fractured reservoirs. Producing mechanisms is different in fractured reservoirs in comparison with conventional reservoirs. Molecular diffusion is one of the mechanisms that along with gravity drainage can increase oil recovery in fractured reservoirs during gas injection. In this work, the effect of molecular diffusion in CO2 and hydrocarbon gas injection as an EOR (enhanced oil recovery) process is investigated using compositional simulation in a single matrix block and a sector model of an Iranian natural fractured reservoir. The effect of the matrix permeability, matrix and fracture permeability difference, matrix porosity, matrix gas-oil capillary pressure and injection gas composition are checked in single matrix blocks, and then the influence of diffusion is investigated on the recovery of the sector model during the CO2 and hydrocarbon gas injection. The results show that molecular diffusion raises oil recovery by increasing the mass transfer rate between the matrix and fracture during miscible gas injection (CO2 and hydrocarbon gas). The low matrix permeability and high gas-oil capillary pressure within the matrix oil make smaller displacement efficiency during gravity drainage. In the sector model, the molecular diffusion increases the ultimate oil recovery by about %2 and %5 in CO2 and hydrocarbon gas injection, respectively by delaying gas breakthrough in an production well and maintaining reservoir pressure.

Using of well logs in un-cored wells in order to identify rock strata related features usually has been discussed between the geologists. In this study, firstly, based on drilling cores, depositional sequences and surfaces of the Permo-Triassic successions in the Persian Gulf and Coastal Fars areas are identified. Then, using processed gamma and density well logs (wavelet analysis), in Cyclolog software, sequence stratigraphic surfaces including sequence boundary and maximum flooding surfaces are recognized and compared with the petrographical results. The recognized surfaces based on gamma ray logs are more compatible with the identified surfaces based on depositional facies, than results of density well logs. According to decreasing and increasing trends and turning points on the processed gamma ray and density well logs of the studied wells and fields, several (isochronous) correlatable surfaces are recognized. Rather than gamma ray and density well logs, Sonic, Neutron, Potassium, Thorium, spectral gamma ray and resistivity, are analyzed using wavelet method which gamma, Potassium, Thorium and Neutron well logs show same results.

We conducted a set of molecular dynamics simulations, as the first comparative study of the adsorption behavior of liquid hydrocarbon (propane, n-hexane, n-heptane, n-decane)/acid gases/water molecules over {} calcite surface and {001} octahedral kaolinite surface in nano-confined slit. According to atomic z-density profiles, hydrocarbon molecules have higher tendency towards the {} calcite surface than the {001} octahedral kaolinite surface. In addition, water molecules showed the same tendency for stronger adsorption over calcite surface than kaolinite. In contrast, acid gas molecules showed higher tendency towards kaolinite surface than calcite surface. This behavior was spotted within nanometer-sized slit pores. The results also pointed to reduction in self-diffusion coefficient of molecules with strong adsorption over mineral surfaces in nano-confined environment. Existence of a water phase in the middle-region of slit was confirmed by the molecular dynamics simulations’ results.

Ni-based catalysts demonstrated the beneficial performance in oxidative dehydrogenation. Magnesium oxide and zirconium oxide have been used in order to supply basic and acidic properties for the catalyst, respectively. Thus, Ni/Z25M75 nanocatalyst has been synthesized and evaluated in the conversion of ethane to ethylene in the presence of oxygen and carbon dioxide. For comparison purposes, Ni/Z25M75 has been synthesized via two different methods. The obtained catalysts have been characterized by XRD, FESEM, EDX, BET and FTIR. The XRD analysis demonstrated that the sample prepared via impregnation had smaller crystallite size. Moreover, FESEM images illustrated larger particle size of the sample prepared using the sol-gel method. Finally, nano-catalyat practical evaluations during oxidative dehydrogenation were done in the range of 500-650 °C. According to the catalytic tests, the nanocatalyst synthesized via the impregnation had better performance in reaction in comparison to the sol-gel one in the terms of conversion and yield. In this study, %67.23 yield obtained using the nanocatalyst has beenprepared via impregnation method.

This article aimed to explore the reservoir potential of the two formations, namely Apsheron and Aghchagil which primarily are comprised of sand, silt and shail. To this end, the existing thin sections taken from cutting drilling pertaining well A were considered. Consequently, four facies of sandy silt, sandy mud, silt and mud were discovered. Based on the variations taken place in the gamma ray (GR) log and sedimentary facies, the intended well was divided into eight zones. Given its completeness of the petrophysical and geological data for considering reservoir quality, the zone #7 proved to be the best case for this study. Following this process, corrected gamma ray (CGR), neutron porosity hydrogen index (NPHI) and density log (RHOZ) were selected as the input data for electrofacies modeling; therefore, through making use of MRGC clustering model, the amounts of these logs were clustered in five electrofacies clusters. Electrofacies #1 was marked, in terms of high degrees of CGR and RHOZ and low degree of NPHI, as possessing the lowest level of reservoir potential. Similarly, electrofacies #5 was marked, in terms of low degree of CGR and RHOZ and high degree of NPHI, as possessing the highest level of reservoir potential. On the other hand, the comparison between the electrofacies and sedimentary facies demonstrates the electrofacies correlation ranging from the highest to lowest quality facies, namely silt, sandy mud and mud, respectively. The results have revealed that the petrophysical data within the wells demonstrating incomplete data might come in handy for the reservoir potential analysis.

Production-injection optimization has been the subject of various researches due to its complicated and expensive computations. The main reason for this complexity is number of reservoir simulation runs is needed to predict reservoir performance. These numerical reservoir simulations are computationally expensive and time consuming. Therefore, finding a way to reduce the computational burden of reservoir simulation will facilitate the optimization process. One of the methods for reducing the complexity of reservoir simulation is Reduced Order Modeling (ROM) which has been recently introduced for improving efficiency of open source reservoir simulators. In this paper, an ROM method based on Artificial Neural Networks (ANN) and Discrete Empirical Interpolation Method (DEIM) is proposed to resolve the curse of dimensionality while simulating reservoir dynamics with acceptable accuracy. This method is also applicable to black box reservoir simulators. The performance of the suggested ANN-DEIM algorithm has been investigated on a case study on Brugge field. The reduced model well represent the reservoir dynamic behavior while reducing run time by a factor of eight comparing with that of a full order reservoir simulator. ANN-DEIM also has been applied in production-injection optimization of Brugge filed using a Pattern Search optimization algorithm. The proposed method can reduce optimization time by 7 times while leading to %11 improvement in Net Present Value (NPV) over the initial solution used in the optimization process.

Salty formations are considered as one of the most important petroleum traps. Thus, oil well drilling in salty formations and its support are among the most significant issues in drilling engineering and one of the most important factors in the life of an oil well. Not only does the loss of these wells cause waste of time and money, but it also hinders the exploitation of large volumes of reservoirs. Among the problems which occur during and after the drilling operations in salty formations, we can mention some of the important problems; such as, trapping of the drill string, decrease in the diameter of the well, and crumpling or shearing in the casing. Convergence of the well lining in salty formations is caused by creep. Creep is a time-dependent phenomenon which occurs under constant stress. Initially, the geo-mechanical properties of one of the wells in Kupal oil field were obtained in this study by sampling and laboratory testing. Afterwards, using the results of a creep test on the sample, the creep behavior of a salt layer around the well was modeled by FLAC2D software. The modeling was done in the two states of drilling ((1) during the drilling and (2) after the drilling (in contact with the casing)) by using the Viscoplastic-burger model. Modeling during the drilling illustrated that using drilling fluid with the weight of 18 pounds per gallon controlled the convergence very well. The findings would also demonstrated that casing rupture would not occur if the cement work behind the casing was appropriate.

Fluid inclusions are closed capsules wich have retained fluid information completely since their entrapment time. These important fluid information parameters are temperature and fluid composition. Geochemical study of fluid inclusions from Mansuri oil field using microthermometry analysis investigates application of fluid inclusion properties. Analytical results indicated that Bangestan Formation is a potential hydrocarbon reservoir. Hydrocarbon-bearing fluid inclusion was noticed only in one well (MI_44E) from Mansuri oil field, and therefore detailed investigation is proposed. Detailed sample analyses resulted in identification of 3 types of fluid inclusion generation with distinct characteristics. All fluid inclusions are described as primary in origin, but they show subtle differences in terms of cement type, temperature of homogenization and salinity. Oil inclusions were noticed only in type 3 generation which is described by varied API Gravity with yellow to blue colors suggesting mature oil (93.1◦C), salinity in the range of 11.46 to 18.47 % at depth 3425.9 meter. Finally, it is concluded that only Ilam reservoir from Bangestan group would possibly be favorable to exploration and field development.

The gas flooding is one of the most common methods for enhancing oil recovery. However, some problems; such as, gas uptake reduces this method’s efficiency. The foam formation reduces the relative permeability of the gas and improves this technique. However, the generated foam by the combination of water and gas does not have enough stability. Thus, surfactant is used for many years. However, the foam stabilized by surfactants is problematic in high temperatures and salt content. The studies have shown that the foam stabilized with Nanoparticles can endure the harsh conditions. Since the presence of oil in the reservoir is inevitable, investigating the effects of crude oil on the foam is of special importance. In this project, the foam generated by Nano-silica and SDS is studied. Then the differences between this foam and the foam generated by only surfactant is discussed. The effect of different kinds of crude oils with different viscosities on foam structure is discussed too. For studying the foam ability and foam stability in the presence of different concentration of these crude oils, the static method called “mixing” is used by the setup that is designed for this job. The results show that nanoparticles do not effect foam ability but increase the foam stability significantly. Regarding the effect of crude oil, it was also determined that the presence of crude oil reduces foam stability and by increasing oil concentration, the stability reduces more. It also turned out that with increasing oil viscosity, foam stability and properties will be improved.

According to Kyoto protocol, carbon dioxide is one of the six large greenhouse gases which causes global warming. Therefor it is very important to prevent it from entering the atmosphere. The gas hydrate technology is one of the newest methods of carbon dioxide separation, but slow kinetics of this technology is one of the major obstacles to industrialize the process. The induction time of carbon dioxide hydrate formation and the amount of gas have been consumed for the systems of water carbon dioxide and water TBAF carbon dioxide were measured in this research. The experiments were done in a 169 cm3 batch reactor and at temperature 278.15 K and initial pressure 3.8 MPa. Utilization of 5 wt% TBAF decreases the induction time of hydrate formation from 73 min to 0.9 min. The amount of carbon dioxide consumed within 40 min and 350 min of experiments was measured and reported. Utilization of 1, 4, and 5 wt% TBAF within 40 min of experiments increase the amount of carbon dioxide consumed 18.5% ,39.3%, and 71.9%, respectively.

In this study, a 2D numerical model is investigated for removal of CO2 in a hydrophobic polyvinylidene fluoride (PVDF) hollow fiber membrane contactor (HFMC) using the computational fluid dynamics (CFD) method. The model considers axial and radial diffusion in the membrane contactor. It also considers convection in the tube and shell side. The model governing equations were solved with using finite-element method. Simulation predictions were validated with the experimental data obtained from literature for CO2 absorption from the gas mixture by water. The simulation predictions were in good agreement. The results of this model are in good agreement with experimental data CO2 removal from the gas mixture by water. In velocity 5 m/s absorbent fluid removal efficiency carbon dioxide at a constant temperature of 10 and 40 °C, respectively, 55.36 and 46.25 %. In velocity of 5 m/s absorbent fluid and 0.2 m/s gas mixture removal efficiency of carbon dioxide absorbent 51.43 and 23.34 % respectively during counter current and co-current flow. Increasing liquid velocity led to an increase in removal efficiency of carbon dioxide. By increasing the gas mixture velocity, removal efficiency is reduced. It is shown that this method is able to predict the performance of the membrane contactor hollow fiber to absorb CO2 from the gas mixture.

In this study, the comprehensive review of empirical and analytical correlations, which are presented for estimation of the relative permeability of two-phase systems, is performed. 11 common and widely used correlations for modeling of two-phase flow of oil - water in porous media including the empirical correlations of Honarpour et al., Ibrahim & Koederitz and Al-Fattah and also those correlations which have adjustable parameters; such as, Corey generalized correlation, Brooks and Corey generalized correlation, Sigmund & McCaffery, Chierici, Van Genuchten-Maulem, LET, Ke and Li et al. were used. The accuracy of the above correlations was evaluated by using 644 experimental data points related to oil - water systems. Generalized Reduced Gradient nonlinear optimization method has been used locally and globally for determining the adjustable parameters of the parametric models. According to the performed adjustment and optimization, Sigmund & McCaffery and LET correlations showed the best agreement with experimental data of oil and water relative permeability, respectively. The decision tree for the best correlation to estimate the relative permeability in carbonate and sandstone rocks as well as for three states of wettability water-wet, intermediate-wet and oil-wet was presented. Also, due to the weakness of the correlations with adjustable parameters to be dependent on experimental relative permeability data in determining the values of their parameters, the best values of the parameters of these correlations were determined using global optimization on a wide range of experimental data. The results were reported for 4 correlations with the highest accuracy.