Study of the thermodynamic behaviour of CaCl 2 -H 2 O-CO 2 systems is important in different H 2 O-CO 2 is a common system in CO 2 also appears as the spent acid. Hence, study of the behaviour of this system and the solubility of CO 2 in CaCl 2 brine in different thermodynamic conditions is critical.In this study, CO 2 solubility in 0, 1.90 and 4.80 mol/L CaCl 2 solutions at 328.15 to 375.15 K and 68.9 to 206.8 bar were measured. These values are normal for oil reservoirs. A popular thermodynamic model is available in the literature for estimating the CO 2 solubility in pure water and NaCl solutions. In 2 as well. Based on the measured data, the component interaction parameters in the base model were adjusted for a CaCl 2 -H 2 O-CO 2 system. The developed model could predict CO 2 solubility in different conditions improvement is up to 65% better than in the base model. This model can be used in Darcy scale models (HCl) is one of the most common acids used during carbonate 2 , water and CaCl 2 are produced from the reaction of HCl and calcite.

Carbonate matrix acidizing is widely used in oil fields as a simple and easy method of production enhancement. However, the dissolution pattern created due to the reaction between the acid and the carbonates is a complex phenomenon. Several experimental and modeling studies have been carried out to simplify this process and design the optimum conditions for acidizing. One approach is to develop continuum models to simulate the dissolution process in the core scale. Conventional modeling approaches typically do not consider the effects of spent acid in the models. However, there are a few studies and observations on the solubility of CO2 in the CaCl2-H2O-CO2 system, which shows the possibility of formation of a separate CO2 phase during acidizing. The presence of CO2 as a separate phase affects the dominant wormhole propagation and also the dissolution regime. Moreover, the acid/rock reaction leads to the change of physical properties of the flowing fluid. Hence, neglecting the alterations in the physical properties of the moving fluid, such as density and viscosity, affects the accuracy of the models. In this study, a basic model previously introduced in the Darcy scale is developed to consider the effect of reaction products on the overall acidizing performance. A thermodynamic model is used to estimate the CO2 solubility in the spent acid. The insoluble CO2 may change the relative permeability of the reactants and influence on the optimum conditions. Furthermore, the physical properties of the fluid are estimated and updated at each step of the modeling. Consideration of the spent acid effects in the modeling can improve the modeling accuracy. The developed model has the ability to consider the effect of pressure and temperature of the medium on the optimum conditions. In addition, the developed model has shown better predictions by considering the physical changes during the dissolution.

Managing oil production from reservoirs to maximize the future economic return of the asset is an important issue in petroleum engineering. In many applications in reservoir modeling and management, there is a need for rapid estimation of large-scale reservoirs. The capacitance-resistive model (CRM), regarded as a promising rapid evaluator of reservoir performance, has recently been used for simulation of single-layer reservoirs. Injection and production rates are considered as input and output signals in this model. Connections between the wells and the effects of injection rates on production rates are calculated based on these signals to develop a simple model for the reservoir. In this study, CRM is improved to model a multilayer reservoir and is applied to estimate and optimize waterflooding performance in an Iranian layered reservoir. In this regard, CRM is coupled with production logging tools (PLT) data to study the effects of layers. A fractional-flow model is also coupled with the developed CRM to estimate oil production. Genetic algorithm (GA) method is used to minimize the error objective function for the total production history and oil production history to evaluate model parameters. GA is then used to maximize oil production by reallocating the injected water volumes, which is the main purpose of this research. The results show that our fast method is able to model liquid and oil production history and is in good agreement with available field data. Taking into account the reservoir constraints, the optimal injection schemes have been obtained. For the proposed injection profile, the field hydrocarbon production will increase by up to 1.8% until 2016. Also, the wells will reach the water-cut constraint 2 yr later than the current situation, which increases the production period of the field.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCapacitance-resistive model is a new method to quantify communication between vertical wells in a reservoir. This method is based on the contribution of each injector on each producer. Capacitance-resistive method uses production and injection rate data to develop and calibrate a model to predict the future performance of the producer wells. The proposed procedure uses a nonlinear signal-processing model to provide information about the connectivity between wells and presence of flow barriers and fractures. In this paper, we present a new method to estimate the fracture distribution in the reservoir using Capacitance-resistive model. We focused on the analysis of the relation between each injector/producer pair. We analyzed the connectivity weight factor of each injector and the neighboring producers to quantify the fracture distribution at each section of the reservoir. Hence, the developed model provides the fast estimation of the fracture distribution using only the flow rate data.The developed model has been tested for different synthetic fractured reservoir case studies. The results are in good agreement in comparison with the fine grid numerical simulation results. It showed that our new approach has the capability to compute the fracture distribution much faster and cheaper than the numerical simulations. By the new developed model, it is possible to estimate the fracture distribution easily and accurately in reservoirs, which has an important role in the field development, drilling new wells and future injection schedule.

Very few thermodynamic models exist for estimation of density alteration due to solution of CO2 in a pure H2O and CaCl2–H2O system. All of these models require density of CaCl2 solution to estimate density of CaCl2–H2O–CO2 system. Similarly, models presented to calculate CaCl2 solution density need pure H2O density in advance. The main approach to model density of CaCl2–H2O–CO2 system is based on estimation of density alteration of CaCl2–H2O system due to the solution of CO2 mole fraction. Hence, to estimate CO2–CaCl2–H2O system density, density of CaCl2 solution is necessary, and to estimate density of CaCl2–H2O system, density of pure H2O is required in advance. Firstly in this paper, density of 0, 1.91, and 4.85 mol/kg CaCl2 solutions saturated with CO2 at 328.15 to 375.15 °K and 68.9 to 206.8 Bar were measured through laboratory experiments. Then, a new model is developed to estimate the density of CaCl2 solutions containing CO2 based on the experiments conducted in this study. The average and maximum absolute deviations of the new model from the experimental data are 0.0047 and 0.0177, respectively. Hence, the new model combined with other existing models to separately calculate density of the CaCl2 solution can be used to accurately predict density of the CaCl2–H2O–CO2 system in a wide range of P-T applicable for subsurface reservoirs.