This study aims to evaluate a wide variety of thermal processes in Boyacá area, located in Guárico state in the Southern flank of the Orinoco River, Basin of Venezuela, which holds an extension of 1247 km2 of extra heavy oil with an API Gravity between 4–8 (API: 4–8), porosities between 25–32% and permeabilities of 2–15 Darcies. Block 06 produced through 7 wells, two of which did not produce, while others two produced by Cyclic Steam Stimulation (CSS) as a test. Results from these tests indicate success in one well which had an accumulated oil production of 26179 STB in one cycle. Synthetical correlations were used in order to estimate fluid and rock properties, considering data obtained from nearby blocks. Geoestatistical model resulted from a refinement of the entire Boyacá area. This new model was classified in three ranges of continuous net sand thickness. First step involved an analysis of this block using."screening criteria" to determine which thermal process was appropriated to apply. As a result, steams flooding based technologies were recommended due to their power to increase the recovery factor in heavy and extra heavy oil reservoirs, providing the required heat content of steam (1200BTU/lb). A following step was building sector models in order to simulate the production history in one of the CSS wells, to simulate each thermal process and to optimize operational parameters. Subsequently, CSS and SAGD (Steam Assisted Gravitational Drainage) were simultaneously simulated. According to these simulations, it is feasible to maximize the recovery of this block up to 30% using this kind of technology. Furthermore, the best economical indicators were obtained through a combination of CSS+SAGD resulting in a net present value of 1521 M$, internal return rate of 15%, operational costs of 16 $/Bbl for an economical horizon of 20 years.
A meandering system where sandbodies produced are complex, so that fluvial deltaic reservoir consist of channel belt sandbodies with highly variable permeability patterns pose a significant challenge for further development of a mature oil field in the Southwest Venezuela. To obtain an optimal strategy a multi-disciplinary reservoir characterization study was carried out. This study combined all available data (geophysics, geology, petrophysics, and engineering) into a 3D stochastic geo-model to build a reservoir simulation model, many sensitivities with grid size and reservoir description in fluvially dominated deltaic facies were undertaken. These sensitivities included various assumptions on sand content of main producing horizons, sandbody dimensions, permeability distribution, and continuity of flood plain acting as vertical barriers in some reservoir areas. All these sensitivities were tested during history matching as alternatives to reach a history match. Drilling locations and some exploitation strategies were made in order to improve the oil recovery factor through closing some wells for several periods (3 months - 6 months) and then opening those wells, this technique helped to decrease the water production rate and increased slightly the oil production rate. The associated economic evaluations were based on simulated forecasts while connected volume calculation was made for the chosen realization.
This paper aims to address calibration of a coreflood Alkali Surfactant Polymer (ASP) formulation experiment through parametrization of fluid-fluid and rock-fluid interactions considering cation exchange capacity and by rock to guide an ASP pilot design. First of all, a series of chemical formulation experiments were studied in cores drilled from clastic reservoir so that displacement lab tests were run on linear and radial cores to determine the potential for oil recovery by ASP flooding and recommended the chemical formulation and flooding schemes, in terms of oil recovery. Therefore, to simulate the process, those tests performed with radial core injection were taken, because this type of test has a better representation of the fluid flow in reservoir, the fluids are injected by a perforation in the center of the core, moving in a radial direction the fluids inside the porous medium. Subsequently, displaced fluids are collected on the periphery of the core carrier and stored in graduated test tubes. The recommended test was carried out to the phase of numerical simulation and historical matching. Reservoir simulation is one of the most important tools available to predict behavior under chemical flooding conditions and to study sensitivities based on cost-effective process implementation. Then, a radial core simulation model was designed from formulation data with porosity of 42.6%, a pore volume (PV) of 344.45 ml, radius of 7.17 cm and weight of 1225.84 g. The initial oil saturation was 0.748 PV (257.58 ml), with a critical water saturation of 0.252 PV (86.78 ml). For the simulation model historical matching, adjustments were made until an acceptable comparison was obtained with laboratory test production data through parameterization of relative permeability curves, chemical adsorption parameters, polymer viscosity, among others; resulting in an accumulated effluents production mass 37% greater for alkali than obtained in the historical, regarding to surfactant the deviation was 8% considered acceptable and for the polymer the adjustment was very close. For the injector well bottom pressure, the viscosity ratio of the mixture was considered based on the polymer concentration and the effect of the shear rate on the viscosity of the polymer as well as the effect of salinity in the alkali case. Finally, a calibrated coreflood numerical simulation model was obtained for ASP flooding to design an ASP Pilot with a residual oil saturation of 0.09 PV (31 ml) meaning 64% more recovered oil compared to a waterflooding case.
A detailed seismic interpretation for reservoir characterization is a powerful tool to obtain information in the inter-well area for the purposes of field management and development. This paper presents a workflow approach to characterize La Victoria Field reservoirs, which belongs to Apure State in the Southwest of Venezuela, particularly Escandalosa M Sand of Escandalosa Formation. The available 3D seismic data have been used to predict small-scale faults as well as presence of internal compartments where undrained zones or bypassed oil might be located in a mature oilfield. Additionally, reservoir engineering techniques as numerical simulation helped to verify reservoir parameters estimated by history matching in a black oil simulator, such as the sealing character of some faults, identified from seismic interpretation. Introduction La Victoria Oilfield is located in Apure State, Southwest of Venezuela, specifically at 60 km to the Southwest of Guasdualito Village and 6 Km to the West of Colombian - Venezuelan boundary, between Uribante - Apure Rivers (North) and Arauca River (South). This oilfield produces from Tertiary and Cretaceous reservoirs. The Escandalosa M Sand is a cretaceous unit, which highly homogeneous; consequently, the structural characterization is the key in order to find drilling opportunities in this field. Seismic attributes reveal features and patterns; which can be useful to understand the geological structure and to build a robust 3D geomodel. Also, this reservoir represents a mature reservoir, in consequence is necessary to do a detailed geological and geophysical and reservoir engineering analysis to find undrained zones or bypassed oil to propose an optimal placement of a well. The aim of this work is to present a methodology for creating an Integrated Structural Geological Model from seismic attributes and well logs in order to build a 3D geomodel that reproduces as exactly as possible the small geological features, and finally create the simulation model which allows identifying undrained zones. Although this work was made along of all oilfield, we will focus this article on the northern part of the field, because was there where the locations were proposed and drilled with excellent results, confirming the results of this study.
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