TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper summarizes the results of several successful WAG projects presented in many Improved Oil Recovery (IOR) Symposiums, indicating the main technical and operational issues considered in the development and implementation of such projects, and the management strategy for monitoring the process (Refs. 1,2,3,4). The results from these field applications will serve as useful guides and examples for improving reserves from many of our mature fields, and would lead to rethinking our strategy of reservoir development and new technology application for significant reserves enhancement in Venezuela. The paper focus on the selection of the technical aspects that must be consider in the implementation and management of the Water Alternating Gas (WAG) Injection process, providing an useable reference for the front line geoscientists, reservoir engineers, production operation engineers and technical managers who wish to obtain a technical and operational overview of the process as applied in the petroleum industry.Managing WAG injection projects requires making decisions regarding to the WAG ratio, half-cycle-slug size, and ultimate solvent slug size for each WAG injector in the field. The impact of these decisions affects the capital cost of solvent purchase, water and gas plant loads, fluid handling and lifting operation costs, and ultimate incremental oil recovery. Simulation models provide a tool for examining strategies for these decisions. However, it must be able to address operational impacts such as lift method and problems, injecting plugging, workovers and facilities operations. Project monitoring incorporating actual performance data into the reservoir models provides an excellent diagnostic tool for decision making. The technical considerations for managing WAG projects presented in this paper can be used as a methodology for monitoring projects performance at pattern and full field level, increasing understanding of the process performance, and improving decision making.

This paper describes a complex volatile oil reservoir fluid characterization process to develop an equation of state for compositional reservoir fluid simulation modeling of the asphaltene flocculation-precipitation phenomena, including the impact on rock permeability. The process consist on lumping the available fluid sample composition into five components, in order to split the heaviest component into its paraffinic, naphthalene, and aromatic constituents being an important part of solid precipitation, which generally form wax and the heaviest aromatic is the major constituent (Ref. 1). As consequence results a composition with seven components used to reproduce the available experiments. The multiphase flash experiment simulation at different temperatures, allow reproducing experimental data from isothermal depressurization of the fluids, determining the asphaltene appearance and disappearance pressure, by observing the behavior of each component on the liquid phase with pressure. The beginning of the increase in the slope of the curve indicates an increase of the asphaltene content on the liquid phase. As consequence, reservoir and facilities plugging may be anticipated. Based on the results of the core oil injection experiment, the effect of reservoir pressure reduction on core permeability to oil was reproduced, observing important formation permeability reduction in good to intermediate quality reservoir regions. This is modeled by modifications of the rock compaction, pore volume and changes on transmissibility with pressure. Sensitivities to different reservoir modeling strategies allow to observe the critical time during the reservoir depletion live, indicating the necessity of maintaining the reservoir pressure above the point at the beginning of maximum increase of the slope of the curve of asphaltene evolution on the liquid phase. Introduction The asphaltene precipitation during primary depletion of highly under saturated near critical oil reservoirs is a complex problem resulting into blocking of the formation and production facilities, and approximations to model the phenomena has been used in compositional reservoir simulation (Refs. 1, 2, 3, 4, 5). The precipitation increases as the reservoir pressure decrease from the upper onset pressure to the saturation pressure. In the reservoir, the precipitated asphaltene can remain in suspension and flow within the oil phase, or it can be deposit on the rock surface, reducing the oil production due to alteration of formation permeability and rock wetability (Ref. 2). The main deposition mechanisms are absorption and mechanical entrapment causing blocking of the formation and alteration of the rock wetability (from being water wet to oil wet). The asphalting flocculation takes place when the oil composition changes because the stabilized asphalten exist in equilibrium, and it is altered when the oil chemical composition changes altering the delicate balance among resins and asphalt or the relationship among polar and no-polar components. Additionally, the no-polar solvents extract the stabilizers agents of the asphaltens causing the precipitation, also for reduction in the pressure of the system and changes of temperature, causing lost of production due to reservoir and production lines obstruction (Ref. 6). Historical review Asphaltenes deposition has been observed in the production pipe of high pressure highly undersaturated volatile oil Venezuela reservoirs; this has been associated to decrease of the amount of asphalts in the surface oil based on sampling observations, identifying significant changes in the fluid composition (Ref. 6).

Maraven S.A is considering to initiate a gas injection project in a large and geologically complex volatile-oil reservoir, located in Lake Maracaibo-Venezuela. This paper describes the methodology used to carry out sensitivities to evaluate the feasibility of using a pseudo compositional option of a black-oil simulator to conduct the 3-D simulations. The first task of the study was to decide whether geological complexities or phase behavior had a larger influence on reservoir performance. Therefore, 1-D sensibility runs were carried out using a fully compositional simulator, and a pseudo compositional simulator to compare compositional effects, grid-block size required to reduce numerical dispersion, effect of displacement pressure, and the use of different injection gases. In the following phase, 2-D simulations were conducted to investigate the effects of heterogeneities on recovery, and the feasibility of lumping the sedimentological facies into flow units without modify the original sedimentological reservoir description. The results showed that the simulated behaviour with the pseudo-compositional simulator were more sensitive to grid-block size, and numerical dispersion. Also, indicated that adecuatelly modelling of internal reservoir heterogeneities is quit relevant. The simulation results, allowed to observe that the pseudo compositional simulator formulation does not take into account the miscibility mechanism for multiple contacts of gas and reservoir oil. Also, at the current reservoir pressure small differences were observed in the results of both models, and large reductions in running time were obtained in the pseudo compositional runs. The previous results enhanced with the ability to permit a better description of the reservoir heterogeneities, indicated superiority of the pseudo compositional model to carry out the 3-D simulations.

A dual porosity simulator was used to evaluate the feasibility of drilling high angle slant wells in the naturally fractured cretaceous reservoir VLA-515, which is located in a geologically complex zone constituted by interconnected fractures where the risk and drilling costs are considerably high. Simulations were conducted to reproduce the existing reservoir conditions, and predictions were made to compare the performance of stimulated vertical wells with horizontal, and slant wells. The production potential predicted for the slant well was twice higher than the achieved by the vertical well, in addition of increasing the oil recovery by 3 %. Simulation results showed that the slant well will recover aproximately 9 MMSTBO during the first 5 years, while the vertical well requires 11 years to obtain the same cumulative production. Finally, under the conditions of the VLA-515 cretaceous reservoir a 55 degrees slant well will achieve higher recovery than an horizontal and stimulated vertical wells, due to higher amount of contacted fractures as consecuence of its penetration angle into the reservoir.

The paper describes the results of a multidisciplinary study aimed at optimizing the performance and reducing the gas requirements of a gas injection project in a complex volatile oil reservoir situated in Lake Maracaibo Basin in Western Venezuela. A 3-D reservoir simulation model with corner point geometry and multiple crisscrossing faults were constructed to achieve the objectives. The fluid samples were properly characterized for input to the model. A continuous team interaction between the various geoscience and engineering disciplines facilitated the proper characterization of the reservoir heterogeneities which in turn enabled the history matching of the field performance. The integrated effort culminated in accurate simulation of the reservoir pressure profile and detailed representation of the reservoir heterogeneities. Sensitivities were carried out with the model to investigate various exploitation schemes for improving the oil recovery. A multidisciplinary team effort followed to evaluate the sand continuity, sedimentological and petrophysical characteristics and to select the appropriate locations of inverted 7-spot patterns for implementation of the Water Alternated Gas Injection process (WAG) in the regions identified by the model as poorly depleted. The simulation results indicated that a better pressure support and consequently, a more improved oil recovery can be achieved by the WAG process (36 and 430/a of the OOIP for the 20 and 30 years of the predicted cases respectively). Furthermore, the results show that the initial gas requirement can be substantially reduced to 30 MMSCF/D and a gas production of up to 80 MMSCF/D can be obtained by year 2004. This gas production will be sufficient to maintain the injection requirement for the WAG process in the later stages. Introduction The Eocene C is a deep, large and geologically complex, volatile oil reservoir, located in Block III, Lake Maracaibo, Venezuela (Fig. 1). The reservoir structure is an elongated flank, 16 by 4 kilometers, with dip ranging from 2 to 5 degrees. The reservoir is composed of low permeability sands (20 – 600 Md.) and a crude whose composition is near to critical point at initial conditions. The estimated OOIP was 1636 MMSTB of 48 degrees API gravity crude, and cumulative production on January 1995 was 289 MMSTB (17.6 %) of OOIP. From 1960 until 1992, the reservoir has been producing by natural depletion. The. reservoir pressure has declined from its initial value of 5900 psia to the current value of 3450 psia which is well below the bubble point pressure (4200 psia). A gas injection project was initiated in 1972 into the lower C-455 and C-460 sands to arrest the pressure decline in this heterogeneous and geologically complex reservoir whose crude is highly volatile. During the reservoir exploitation history, several studies have been performed mainly to define and understand the reservoir geology and recovery mechanism (Refs. 1,2,3,4,5). These studies have shown that an appropriate modeling of the complex reservoir sedimentology and compositional effects of the reservoir fluids are key factors for reproducing the reservoir performance. A 3-dimensional reservoir simulation model (27 × 59 × 10) was developed incorporating all the multidisciplinary information available to date (Refs. 1,5,6) for matching the historical reservoir production and pressure performance, and to determine the actual pressure and fluids saturation distribution in the C-455/60 flow units. This allowed an improved characterization of the reservoir heterogeneity and a better understanding of the fluid flow.