Summary A numerical nonisothermal two-phase wellbore model is developed to simulate downward flow of a steam and water mixture in the wellbore. This model entails simultaneous solution of coupled mass and momentum conservation equations inside the wellbore with an energy conservation equation for the fluids within the wellbore, surrounding medium and formation. A new drift-flux model that accounts for slip between the phases inside the wellbore is employed. In addition, a 2D implicit scheme that allows for heat transfer in both the axial and radial directions in the formation is developed. Furthermore, a rigorous nonlinear temperature- and depth-dependent overall heat transfer coefficient is implemented. The model predictions are validated against real field data and other available models. The model is useful for designing well completion and accurately computing the wellbore/formation heat transfer, which is important for estimating oil recovery by using steam injection.

A numerical nonisothermal two-phase wellbore model is developed to simulate downward flow of a steam and water mixture in the wellbore. This model entails simultaneous solution of coupled mass and momentum conservation equations inside the wellbore with an energy conservation equation for the fluids within the wellbore, surrounding medium, and formation. A new drift-flux model that accounts for slip between the phases inside the wellbore is employed. In addition, a two-dimensional implicit scheme that allows for heat transfer in both the axial and radial directions in the formation is developed. Furthermore, a rigorous nonlinear temperature-and depth-dependent overall heat transfer coefficient is implemented. The model predictions are validated against real field data and other available models. The model is useful for designing well completion and accurately computing the wellbore/formation heat transfer, which is very important for estimating oil recovery by using steam injection.

Although several models to determine the formation temperature in the modelling of thermal production and injection processes have already been suggested, there is no rigorous or systematic comparison between these models' predictions that can guide the choice of the most appropriate one. Another issue in thermal wellbore simulators is the commonly used assumption of semisteady-state heat transfer from the wellbore up to the cementing/formation interface. The effect of the semisteady-state assumption vs. the unsteadystate assumption for the heat transfer from the wellbore up to the formation has not received much attention in the literature and can be important in some cases.The results of a detailed analysis of the two previously described issues can be implemented in all thermal wellbore and reservoir simulators to increase their accuracy.The previously described stated issues will be addressed in the present work by developing a numerical nonisothermal twophase wellbore simulator coupled with tubular and cement material and surrounding formation. The first issue will be studied in detail by comparing five different models for the formation temperature treatment (FTT) plugged in the developed thermal wellbore simulator. Investigation of the second issue will be achieved by analyzing the three critical items: first, a 2D heat transfer partial differential equation (PDE) model of the formation is discretized in a general form; second, the gridding system is shifted from the formation toward the casing; and third, an effective specific heat capacity for the casing is used. The effects of choosing different models for FTT and using either the unsteady-state or the semisteady-state assumption in the heat loss from the wellbore up to the formation will be investigated. The model will be validated against field data to show its merits in predicting the casing temperature. The entire wellbore system contains wellbore, tubing, insulation, annulus, casing, cementing and formation. A fundamental understanding of this system is still a challenging issue in the petroleum industry, and its accurate modelling and coupling with reservoirs has become increasingly significant as more energy resources are sought.

Steam injection in naturally fractured heavy oil reservoirs provides an extremely challenging problem as well as a potentially effective and efficient improved oil recovery method. Coupling of the two distinct and contrasting matrix and fracture systems results in a highly non-linear problem, and it gets even more complicated as a result of steep changes in fluid properties due to the thermal effects of steam injection. Modeling and designing an optimum steam injection operation in such systems requires an accurate characterization and representation of a naturally fractured heavy oil reservoir and steam injection operation parameters and dynamics1. In this communication, the results of a feasibility study of steam injection in a highly fractured carbonate reservoir are discussed. The field is a giant structure located in south west of Iran at the coast of Persian Gulf. It is a symmetrical anticline with 56 mile length and 10 mile width in the surface with about 3.6 billion barrels of initial oil in place. The initial pressure is 927 psi at 1700 ft depth. The gravity of the oil is 7.24 °API with viscosity of about 2700 cp. The Geological model was constructed based on the available 2D and 3D seismic investigation and conventional core data from different samples. Extensive fracture characterization has been conducted using core data as well as the petrophysical interpretation using imaging logs. Dynamic reservoir simulation model with thermal option has been developed and used for optimization of different parameters for steam injection and their effect on reservoir performance and recovery factor. Reservoir simulation of the field showed that steam injection could improve oil recovery from zero up to nearly 12 %. Furthermore, the results illustrated that the important parameters for designing the steam injection are different strategies for perforating, well spacing, well type, pattern type and size. Additionally, the effect of other parameters such as injected steam quality, oil-water capillary pressure in matrix blocks, steam injection and oil production rate have been studied. Introduction The K Field is a highly fractured carbonate reservoir with about 3.6 billion barrels of initial oil in place. The two important formations in this field for oil production are Jahrum and Sarvak formations. Therefore, the field has been considered as the first developing extra heavy oil reservoir in Iran. Different scenarios were suggested for this field to put it on production among which steamflooding, cyclic steam stimulation and in situ combustion are the most promising methods because of their thermal nature. Sarvak formation with the average thickness of 985 ft is one of the main formations in this field. Initial oil in place of Sarvak reservoir based on Montecarlo calculations program is estimated at 2.7 billion barrels of oil. Therefore, the reservoir simulation study was focused on this formation. Steamflooding method is much like a waterflooding method since it is injected on a pattern basis. Full potential of Steamflooding method was not realized until commercial steamfloods were started in California2. After that many successful field test were reported in literature for both conventional and fracture reservoirs4, 5, 6. Additionally, it was successful both in light and heavy/ extra heavy oil reservoirs7. This is why we did reservoir simulation study based on this method. The objective of this study is to apply all the available data to construct the most reliable model and then determine if the steamflooding method is a suitable candidate to be implemented in this reservoir. CMG thermal simulator (STARS module) with dual porosity option was chosen for our simulation study and the PVT was tuned by the WinProp module. After construction of the model, we attempted to optimize the most significant field operational parameters. Geography and Geology of the Field K Field is a giant structure located in the southwestern part of Iran in the coast of Persian Gulf. Exploration of the field occurred in 1959 in Jahrum and Sarvak formations as extra heavy oil reservoir.

Typical thermal processes involve sophisticated wellbore configurations, complex fluid flow and heat transfer in tubing, annulus, wellbore completion, and surrounding formation. Despite notable advancements made in wellbore modeling, accurate heat loss modeling is still a challenge using the existing wellbore simulators. This challenge becomes even greater when complex but common wellbore configurations such as multi-parallel or multi-concentric tubings are used in thermal processes such as Steam Assisted Gravity Drainage (SAGD).To improve heat loss estimation, a standalone fully-implicit thermal wellbore simulator is developed that can handle several different wellbore configurations and completions. This simulator uses a fully implicit method to model heat loss from tubing walls to the surrounding formation. Instead of implementing the common Ramey method (1962) for heat loss calculations that has been shown to be a source of large errors, a series of computational fluid dynamical (CFD) models are run for the buoyancy driven flow for different annulus sizes and lengths and numbers of tubings. Based on these CFD models, correlations are derived that can conveniently be used for the more accurate heat loss estimation from the wellbore to the surrounding formation for SAGD injection wells with single or multiple tubing strings. These correlations are embedded in the developed wellbore simulator and results are compared with other heat loss modeling methods to demonstrate its improvements. A series of validations against commercial simulators and field data are presented in this paper.