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 OUR RESERVOIR VISION |
Petroleum reservoirs contain naturally occurring hydrocarbon systems, mixtures of organic compounds that exhibit multiphase behavior over wide ranges of pressures and temperatures. Hydrocarbon accumulations may occur in the gaseous state, the liquid state, or in various combinations of both. These differences in phase behavior, coupled with the physical properties of the reservoir rocks (these properties determine the ease with which the formation can produce at what is considered a commercial rate), result in many different types of hydrocarbon reservoirs with complex behaviors. The task of reservoir engineering is to study the behavior and characteristics of an oil or gas reservoir to determine the course of future development and production that will maximize profit.
Four distinct technical aspects can be defined in reservoir engineering:
- estimation of hydrocarbon in-place;
- determining the fraction of discovered hydrocarbons that can be reasonably recovered;
- the development of a production profile (i.e. establishing a time scale for the recovery)
- providing support to operational activity throughout the lifetime of the reservoir.
Optimizing the field development strategy requires a reservoir model capable of realistically predicting the dynamic behavior of the field in terms of production rates and fluid recovery under different operating conditions. Such a model is constructed by integrating all the available information provided by the different disciplines.
The necessary parameters are obtained from direct measurements and from interpreted data. Seismic data and well logs provide a static description of the reservoir, but only well testing data can provide information on dynamic reservoir response, a key element in the reservoir model's construction.
Predicting the areal movement of fluids in the reservoir, and therefore determining the number of wells required for successful development, their location, and the time of their drilling, is based on the construction of a meaningful and reliable numerical simulation model. This model can be seen as an attempt to describe what occurs in the wide open spaces of the reservoir between scattered points of observation – i.e., the wells.
The reservoir description is based on structural contours and other maps obtained from geophysicists and geologists, combined with formation properties provided by petrophysicists: net pay thicknesses, porosities, and fluid saturations. All this information is integrated with core permeability distributions, fluid properties, and interpreted well test results, to construct some sort of model- simple or complex- depending on the quantity and the quality of available data. The model is used to predict the likely performance of the field under a variety of possible development scenarios. To understand and predict the volumetric behavior of oil and gas reservoirs as a function of pressure, knowledge of the thermodynamic properties of the reservoir fluids and the petrophysical characteristics of the rocks must be obtained.
During the early years of the project, the systematic collection of rate and pressure data, together with PVT fluid properties, permitted the estimation of the strength of any natural energizing mechanism such as water influx from aquifer or gas cap expansion, and also lead to the estimation of hydrocarbons in-place. The estimation of these fundamental factors is accomplished by applying the concept of material balance.
During the development phase of a reservoir, pressure surveys, usually pressure build – ups, are conducted at regular intervals throughout the project lifetime. The frequency of the surveys depends on the significance of the pressure data acquired.
Production profiles are frequently required throughout the lifetime of a project, and their generation is entirely the responsibility of the reservoir engineer. All reservoir engineering problems should be approached in a simple fashion and with the simplest method available because, as L. Dake wrote and frequently used to say, "there seems to be an inverse law applicable to reservoir engineering that the more complex the system, the more appropriate is the attempt at simplicity and the more convincing".
After a reservoir model has been constructed, it must be tested to determine whether it can duplicate field behavior.
Generally, the reservoir description used in the model is validated by running the simulator with historical production and injection data and comparing calculated pressures and fluid movements with actual reservoir performance. A more stringent test is to have the simulator compute the past performance of individual wells, as well as historical pressures and fluid movements. The data used in history matching will vary with the scope of the study, but will usually include reservoir pressure and production data. If the diagnosed reservoir model is consistent, the match between field data and the corresponding calculated models’ responses should be reasonably good and, in many cases, should be easy to improve by adjusting some reservoir model parameters within limits imposed by available knowledge.
Development decisions rely on the prediction of the reservoir’s future behavior, not only in terms of oil recovery and cumulative oil production, but also as forecast by production profiles. |
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