An extra-heavy crude oil underground upgrading process is described which involves the downhole addition of a hydrogen donor additive (tetralin) under steam injection conditions. Using a batch laboratory reactor or a continuous bench scale plant (280–315°C and residence times between 24–64 h), physical simulation experiments showed an increase of at least 3° in API gravity of the treated Extra-Heavy Crude Oil, three-fold viscosity reduction and, approximately, 8% decrease in the asphaltene content with respect to the original crude. It was found that the presence of the natural formation (catalyst) and methane (natural gas) is necessary to enhance the properties of the upgraded crude oil. Compositional-thermal numerical simulations were carried out and the results showed a good match between the calculated and experimental °API gravities of the upgraded crude oil (average relative error 1–4%) for all conditions studied. Similar results were obtained with the asphaltene contents (14–23%), percentage of conversion of the >500°C fraction (12%) and tetralin (16–23%). Introduction Downhole extra-heavy crude oil upgrading processes have high potential value due to the possibility of improving crude oil quality with the concomitant higher benefits obtained by their exploitation. Underground processes leads to several advantages in comparison with aboveground counterparts. First at all, enhanced oil recovery could be obtained by adding additional oil reserves. Also, increase in the volumetric production of wells and lower lifting and transportation costs from the underground to the refining centers could be generated. Finally, the use of porous media (mineral formation) as natural chemical "catalytic reactor" will improve the upgraded crude oil properties with further reductions in expenses during down stream refining operations. Several routes for underground extra-heavy crude oil upgrading have been reported. These concepts involve the following: Physical separations (steam distillation1 or deasphalting2), underground cracking or hydrocracking (visbreaking3–4, hydrogen6 or hydrogen precursor injection6–7) and in situ combustion8–9. In this work, a different concept10 is presented (Fig. 1) involving the underground addition of a hydrogen donor additive (tetralin), which in the presence of steam, natural formation (catalyst) and methane (natural gas), leads to extra-heavy crude oil upgrading. This concept is coupled to a steam stimulation process11 with 70–80% hydrogen donor recycled as depicted in Fig. 1. Specifically, batch reactor and continuous bench scale plant physical simulations are presented under steam injection conditions (280°C, 1600 psi), and crude oil upgrading is measured in terms of its API gravity, viscosity and percentages of asphaltenes. Different extra-heavy crude oils were studied and compositional thermal simulations were carried out in order to model the upgrading process under steam stimulation conditions. Experimental Part The extra-heavy crude oils came from the Orinoco Belt (Hamaca and Cerro Negro) and their properties are listed in Table 1. The percentages of asphaltenes were measured using the ASTM D-3279 and crude oil viscosities in a Brookfield apparatus, model RVTDV-II.

Physical simulation experiments of a Downhole Upgrading Process showed that use of a hydrogen donor additive (tetralin) in the presence of methane (natural gas) and the mineral formation under steam injection conditions (280°C and residence times greater than 24 h) led to an increase of at least three degree in API gravity of the treated Extra-Heavy Crude Oil, three-fold viscosity reduction and, approximately, 8% decrease in the asphaltene content with respect to the original crude. In the present work, a continuous bench scale plant was used at different temperatures (280–315°C) and residence times (24–64 h) for carrying out kinetic studies. A reaction model involving four pseudo-components (light, medium, heavy and asphaltene fractions) was used and the kinetic parameters (pre-exponential factors and activation energies) were determined. Using these data, compositional-thermal numerical simulations were carried out and validated using the bench scale data. The results showed a good match between the calculated and experimental °API gravities of the upgraded crude oil (average relative error 4%). Using the previous model, the Downhole Upgrading Process was numerically simulated under cyclic steam injection conditions (injection of 2500 bbl/d of 1:1 steam/tetralin with 75% quality steam) for 20 days, followed by 10 days of soaking period) in a typical Orinoco Basin reservoir (9°API). The simulation runs showed the production of 12°API upgraded crude oil, accumulated over a 100 day-cycle. However, a reduction in the percentage of conversion of tetralin was observed (0.8%) in comparison with the bench scale experiments (3%), which was attributed to gravitational segregation of the steam coupled with low mixing efficiency of the hydrogen donor with the extra-heavy crude oil at reservoir conditions. Introduction Underground upgrading processes have always been the interest of the petroleum industry mainly because of the intrinsic advantages compared with aboveground counterparts. First at all, lower lifting and transportation costs from the underground to the refining centers will be achieved, with the potential increase of the volumetric production of wells. Thus, a decrease in the consumption of costly light and medium petroleum oils used as solvents for heavy and extra-heavy crude oil production will be also obtained. Finally, the use of porous media (mineral formation) as natural chemical "catalytic reactor" will allow improving the properties of upgraded crude oil with further reductions in expenses during down stream refining operations. Several routes for underground crude oil upgrading have been reported. These concepts involve the following: Downhole steam distillation1, deasphalting2–5, underground visbreaking6–9, hydrogen10–17 or hydrogen precursor injection18–22 and in situ combustion23–25. With the exemption of the later route, the numerical simulation of downhole upgrading processes has been relatively less studied. Shu et al. used a compositional simulation and experimentally measured kinetic data26 to determine the effect of the visbreaking reactions on the percentages of recovery of heavy crude oil produced by cyclic steam injection and steamflood8. For the former route, the authors found an increase of 5% in the oil recovery due to viscosity reduction in the heated zones of the reservoir8. Similarly, Kaskale and Farouq Ali7 reported the numerical simulation of Steamflood in a five-spot array for the production of upgraded Saskatchewan crude oil. These authors found that the upgraded crude is mainly generated at the hotter area (T>220°C) of the reservoir with an overall increase of 13% in the recovery of oil, compared with the cold production simulation7.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA benchmarking study on 43 steamflood of light/medium crude oils was performed, to find attractive reservoir characteristics and successful operational practices that are used worldwide. More than 30 successful projects were analyzed and summarized in a database, which included reservoir properties, best operational practices and results obtained. On average, an incremental oil recovery of 19% OOIP was obtained by steamflooding, during a project lifetime of up to seven years.Based on the successful project characteristics, we developed a model to rank potential reservoirs. Reservoir data were analyzed using standard statistical methods for properties, such as: API gravity, initial oil saturation, reservoir temperature, porosity, initial pressure, depth, net pay, viscosity at reservoir condition, initial (at the beginning of steamdrive)bubble pressure ratio and average permeability. The statistical model ranked the properties on a standardized score scale. A predicted score close to one hundred indicates a high probability of success. Supported by this numerical model, we selected the La Salina reservoir (La Rosa Formation, Lake Maracaibo, Western Venezuela) as a potentially successful reservoir to apply steamflood technology.In addition, unsuccessful projects from two different reservoirs (the Naval Petroleum Reserve No.

Summary Hybrid steam-solvent processes have gained importance as a thermal-recovery process for heavy oils in recent years. Numerous pilot projects during the last decade indicate the increasing interest in this technology. The steam/solvent coinjection process aims to accelerate oil production, increase ultimate oil recovery, reduce energy and water-disposal requirements, and diminish the volume of emitted greenhouse gases compared with the steam-assisted-gravity-drainage (SAGD) process. Among the identified physical mechanisms that play a role during the hybrid steam/solvent processes are the heat-transfer phenomena, the gravity drainage and viscous flow, the solvent mass transfer, and the mass diffusion/dispersion phenomena. The major consequence of this complex interplay is the improvement of oil-phase mobility that is controlled by the reduction in the oil-phase viscosity at the edge of the steam chamber. It follows that a detailed representation of this narrow zone is necessary to capture the involved physical phenomena. In this work, a study of sensitivity to grid size was carried out to define the appropriate grid necessary to represent the near-edge zone of the steam/solvent chamber. Our results for the steam/solvent coinjection process in a homogeneous synthetic reservoir indicate that a decimetric scale is required to represent with a good precision the heat and mass-transfer processes taking place at the edge of the steam chamber. In addition, we present some numerical results of the adaptive dynamic gridding application. Comparison was performed between the SAGD process and steam/solvent coinjection after the characterization and analysis of the mechanisms that govern oil production under typical Athabasca oil-sand conditions. Finally, in the framework of the proposed numerical methodology, the effect of solvent type and injection conditions on the oil-recovery efficiency is quantitatively illustrated. Published data for similar applications are also discussed. It is expected that this work will provide some insight for the simulation community about methodological aspects to be taken into account when hybrid steam/solvent processes would be modeled.

Summary In–situ upgrading (IU) is a promising method of improved viscous– and heavy–oil recovery. The IU process implies a reservoir heating up and exposure to a temperature higher than 300°C for a time period long enough to promote a series of chemical reactions. The pyrolysis reactions produce lighter oleic and gaseous components, while a solid residue remains underground. In this work, we developed a numerical model of IU using laboratory experience (kinetics measurements and core experiments) and validated the results by applying our model to an IU field–scale test published in the literature. Finally, we studied different operational conditions in a search for energy–efficient configurations. In this work, two types of IU experimental data are used from two vertical–tube experiments with Canadian bitumen cores (0.15 and 0.69 m). A general IU numerical model for the different experimental setups has been developed and compared with experimental data, using a commercial reservoir–simulator framework. This model is capable of representing the phase distribution of pseudocomponents, the thermal decomposition reactions of bitumen fractions, and the generation of gases and residue (solid) under thermal cracking conditions. Simulation results for the cores exposed to a temperature of 380°C and production pressure of 15 bar have shown that oil production (per pseudocomponent) and oil–sample quality were well–predicted by the model. Some differences in gas production and total solid residue were observed with respect to laboratory measurements. Computer–assisted history matching was performed using an uncertainty–analysis tool with the most–important model parameters. To better understand IU field–scale test results, the Shell Viking pilot (Peace River) was modeled and analyzed with the proposed IU model. The appropriate gridblock size was determined and the calculation time was reduced using the adaptive mesh–refinement (AMR) technique. The quality of products, the recovery efficiency, and the energy expenses obtained with our model were in good agreement with the field test results. In addition, the conversion results (upgraded oil, gas, and solid residue) from the experiments were compared with those obtained in the field test. Additional analysis was performed to identify energy–efficient configurations and to understand the role of some key variables (e.g., heating period and rate and the production pressure) in the global IU upgrading performance. We discuss these results, which illustrate and quantify the interplay between energy efficiency and productivity indicators.